US20090301727A1 - Apparatus and method for recovering fluids from a well and/or injecting fluids into a well - Google Patents
Apparatus and method for recovering fluids from a well and/or injecting fluids into a well Download PDFInfo
- Publication number
- US20090301727A1 US20090301727A1 US12/541,934 US54193409A US2009301727A1 US 20090301727 A1 US20090301727 A1 US 20090301727A1 US 54193409 A US54193409 A US 54193409A US 2009301727 A1 US2009301727 A1 US 2009301727A1
- Authority
- US
- United States
- Prior art keywords
- fluids
- branch
- bore
- diverter assembly
- production
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Granted
Links
- 239000012530 fluid Substances 0.000 title claims abstract description 404
- 238000000034 method Methods 0.000 title claims abstract description 70
- 238000012545 processing Methods 0.000 claims abstract description 92
- 238000002347 injection Methods 0.000 claims description 84
- 239000007924 injection Substances 0.000 claims description 84
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 31
- 229930195733 hydrocarbon Natural products 0.000 claims description 25
- 150000002430 hydrocarbons Chemical class 0.000 claims description 25
- 238000004891 communication Methods 0.000 claims description 21
- 239000000126 substance Substances 0.000 claims description 20
- 238000000926 separation method Methods 0.000 claims description 14
- 238000005259 measurement Methods 0.000 claims description 9
- 230000008569 process Effects 0.000 claims description 7
- 230000004888 barrier function Effects 0.000 claims description 5
- 239000004215 Carbon black (E152) Substances 0.000 claims description 3
- 238000009529 body temperature measurement Methods 0.000 claims description 2
- 239000007787 solid Substances 0.000 claims description 2
- 238000000605 extraction Methods 0.000 claims 1
- 229910052500 inorganic mineral Inorganic materials 0.000 claims 1
- 239000011707 mineral Substances 0.000 claims 1
- 238000011084 recovery Methods 0.000 abstract description 33
- 238000004519 manufacturing process Methods 0.000 description 271
- 241000191291 Abies alba Species 0.000 description 45
- 235000004507 Abies alba Nutrition 0.000 description 45
- 239000007789 gas Substances 0.000 description 30
- 230000000712 assembly Effects 0.000 description 26
- 238000000429 assembly Methods 0.000 description 26
- 238000013461 design Methods 0.000 description 17
- 238000007789 sealing Methods 0.000 description 14
- 230000006870 function Effects 0.000 description 12
- 230000008901 benefit Effects 0.000 description 8
- 239000004576 sand Substances 0.000 description 8
- 239000002184 metal Substances 0.000 description 7
- 229910052751 metal Inorganic materials 0.000 description 7
- 230000004048 modification Effects 0.000 description 5
- 238000012986 modification Methods 0.000 description 5
- 241000520007 Porcine rubulavirus Species 0.000 description 3
- 230000000903 blocking effect Effects 0.000 description 3
- 238000005520 cutting process Methods 0.000 description 3
- 238000010586 diagram Methods 0.000 description 3
- 238000009434 installation Methods 0.000 description 3
- 230000007246 mechanism Effects 0.000 description 3
- 239000000203 mixture Substances 0.000 description 3
- 238000005086 pumping Methods 0.000 description 3
- 239000002699 waste material Substances 0.000 description 3
- 230000015572 biosynthetic process Effects 0.000 description 2
- 230000008859 change Effects 0.000 description 2
- 238000010276 construction Methods 0.000 description 2
- 238000007796 conventional method Methods 0.000 description 2
- 230000008878 coupling Effects 0.000 description 2
- 238000010168 coupling process Methods 0.000 description 2
- 238000005859 coupling reaction Methods 0.000 description 2
- 230000005611 electricity Effects 0.000 description 2
- 238000005868 electrolysis reaction Methods 0.000 description 2
- 238000003780 insertion Methods 0.000 description 2
- 230000037431 insertion Effects 0.000 description 2
- 239000000463 material Substances 0.000 description 2
- 239000013535 sea water Substances 0.000 description 2
- 230000001960 triggered effect Effects 0.000 description 2
- 229910000831 Steel Inorganic materials 0.000 description 1
- 230000009471 action Effects 0.000 description 1
- 238000005553 drilling Methods 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 210000002969 egg yolk Anatomy 0.000 description 1
- 238000005516 engineering process Methods 0.000 description 1
- 230000007613 environmental effect Effects 0.000 description 1
- 238000007667 floating Methods 0.000 description 1
- 230000006872 improvement Effects 0.000 description 1
- 239000003112 inhibitor Substances 0.000 description 1
- 150000002739 metals Chemical class 0.000 description 1
- 239000003129 oil well Substances 0.000 description 1
- 239000003507 refrigerant Substances 0.000 description 1
- 230000004044 response Effects 0.000 description 1
- 238000009420 retrofitting Methods 0.000 description 1
- 230000000630 rising effect Effects 0.000 description 1
- 230000003068 static effect Effects 0.000 description 1
- -1 steam Substances 0.000 description 1
- 239000010959 steel Substances 0.000 description 1
- 239000004094 surface-active agent Substances 0.000 description 1
- 238000012360 testing method Methods 0.000 description 1
- 238000012546 transfer Methods 0.000 description 1
- 239000002912 waste gas Substances 0.000 description 1
Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
- E21B33/035—Well heads; Setting-up thereof specially adapted for underwater installations
- E21B33/0387—Hydraulic stab connectors
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
- E21B33/035—Well heads; Setting-up thereof specially adapted for underwater installations
- E21B33/0353—Horizontal or spool trees, i.e. without production valves in the vertical main bore
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
- E21B33/04—Casing heads; Suspending casings or tubings in well heads
- E21B33/047—Casing heads; Suspending casings or tubings in well heads for plural tubing strings
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
- E21B33/068—Well heads; Setting-up thereof having provision for introducing objects or fluids into, or removing objects from, wells
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
- E21B33/068—Well heads; Setting-up thereof having provision for introducing objects or fluids into, or removing objects from, wells
- E21B33/076—Well heads; Setting-up thereof having provision for introducing objects or fluids into, or removing objects from, wells specially adapted for underwater installations
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B34/00—Valve arrangements for boreholes or wells
- E21B34/02—Valve arrangements for boreholes or wells in well heads
- E21B34/025—Chokes or valves in wellheads and sub-sea wellheads for variably regulating fluid flow
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
- E21B41/0007—Equipment or details not covered by groups E21B15/00 - E21B40/00 for underwater installations
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/01—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells specially adapted for obtaining from underwater installations
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/162—Injecting fluid from longitudinally spaced locations in injection well
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/34—Arrangements for separating materials produced by the well
- E21B43/36—Underwater separating arrangements
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B34/00—Valve arrangements for boreholes or wells
- E21B34/02—Valve arrangements for boreholes or wells in well heads
- E21B34/04—Valve arrangements for boreholes or wells in well heads in underwater well heads
Definitions
- the present invention relates to apparatus and methods for diverting fluids.
- Embodiments of the invention can be used for recovery and injection Some embodiments relate especially but not exclusively to recovery and injection, into either the same, or a different well.
- Christmas trees are well known in the art of oil and gas wells, and generally comprise an assembly of pipes, valves and fittings installed in a wellhead after completion of drilling and installation of the production tubing to control the flow of oil and gas from the well.
- Subsea Christmas trees typically have at least two bores one of which communicates with the production tubing (the production bore), and the other of which communicates with the annulus (the annulus bore).
- Typical designs of Christmas tree have a side outlet (a production wing branch) to the production bore closed by a production wing valve for removal of production fluids from the production bore.
- the annulus bore also typically has an annulus wing branch with a respective annulus wing valve.
- the top of the production bore and the top of the annulus bore are usually capped by a Christmas tree cap which typically seals off the various bores in the Christmas tree, and provides hydraulic channels for operation of the various valves in the Christmas tree by means of intervention equipment, or remotely from an offshore installation.
- a further alternative is to pressure boost the production fluids by installing a pump from a rig, but this requires a well intervention from the rig, which can be even more expensive than breaking the subsea or seabed pipework.
- a diverter assembly for a manifold of an oil or gas well, comprising a housing having an internal passage, wherein the diverter assembly is adapted to connect to a branch of the manifold.
- a diverter assembly adapted to be inserted within a manifold branch bore, wherein the diverter assembly includes a separator to divide the branch bore into two separate regions.
- the oil or gas well is typically a subsea well but the invention is equally applicable to topside wells.
- the manifold may be a gathering manifold at the junction of several flow lines carrying production fluids from, or conveying injection fluids to, a number of different wells.
- the manifold may be dedicated to a single well; for example, the manifold may comprise a Christmas tree.
- wing branch we mean any branch of the manifold, other than a production bore of a tree.
- the wing branch is typically a lateral branch of the tree, and can be a production or an annulus wing branch connected to a production bore or an annulus bore respectively.
- the housing is attached to a choke body.
- “Choke body” can mean the housing which remains after the manifold's standard choke has been removed.
- the choke may be a choke of a tree, or a choke of any other kind of manifold.
- the diverter assembly could be located in a branch of the manifold (or a branch extension) in series with a choke.
- the diverter assembly could be located between the choke and the production wing valve or between the choke and the branch outlet.
- Further alternative embodiments could have the diverter assembly located in pipework coupled to the manifold, instead of within the manifold itself. Such embodiments allow the diverter assembly to be used in addition to a choke, instead of replacing the choke.
- Embodiments where the diverter assembly is adapted to connect to a branch of a tree means that the tree cap does not have to be removed to fit the diverter assembly.
- Embodiments of the invention can be easily retro-fitted to existing trees.
- the diverter assembly is locatable within a bore in the branch of the manifold.
- the internal passage of the diverter assembly is in communication with the interior of the choke body, or other part of the manifold branch.
- the invention provides the advantage that fluids can be diverted from their usual path between the well bore and the outlet of the wing branch.
- the fluids may be produced fluids being recovered and travelling from the well bore to the outlet of a tree.
- the fluids may be injection fluids travelling in the reverse direction into the well bore.
- the choke is standard equipment, there are well-known and safe techniques of removing and replacing the choke as it wears out. The same tried and tested techniques can be used to remove the choke from the choke body and to clamp the diverter assembly onto the choke body, without the risk of leaking well fluids into the ocean. This enables new pipe work to be connected to the choke body and hence enables safe re-routing of the produced fluids, without having to undertake the considerable risk of disconnecting and reconnecting any of the existing pipes (e.g. the outlet header).
- the choke body may be a production choke body or an annulus choke body.
- a first end of the diverter assembly is provided with a clamp for attachment to a choke body or other part of the manifold branch.
- the housing is cylindrical and the internal passage extends axially through the housing between opposite ends of the housing.
- one end of the internal passage is in a side of the housing.
- the diverter assembly includes separation means to provide two separate regions within the diverter assembly.
- each of these regions has a respective inlet and outlet so that fluid can flow through both of these regions independently.
- the housing includes an axial insert portion.
- the axial insert portion is in the form of a conduit.
- the end of the conduit extends beyond the end of the housing.
- the conduit divides the internal passage into a first region comprising the bore of the conduit and a second region comprising the annulus between the housing and the conduit.
- the conduit is adapted to seal within the inside of the branch (e.g. inside the choke body) to prevent fluid communication between the annulus and the bore of the conduit.
- the axial insert portion is in the form of a stem.
- the axial insert portion is provided with a plug adapted to block an outlet of the Christmas tree, or other kind of manifold.
- the plug is adapted to fit within and seal inside a passage leading to an outlet of a branch of the manifold.
- the diverter assembly provides means for diverting fluids from a first portion of a first flowpath to a second flowpath, and means for diverting the fluids from a second flowpath to a second portion of a first flowpath.
- At least a part of the first flowpath comprises a branch of the manifold.
- the first and second portions of the first flowpath could comprise the bore and the annulus of a conduit.
- a manifold having a branch and a diverter assembly according to the first or second aspects of the invention.
- the diverter assembly is attached to the branch so that the internal passage of the diverter assembly is in communication with the interior of the branch.
- the manifold has a wing branch outlet, and the internal passage of the diverter assembly is in fluid communication with the wing branch outlet.
- a region defined by the diverter assembly is separate from the production bore of the well.
- the internal passage of the diverter assembly is separated from the well bore by a closed valve in the manifold.
- the diverter assembly is provided with an insert in the form of a conduit which defines a first region comprising the bore of the conduit, and a second separate region comprising the annulus between the conduit and the housing.
- one end of the conduit is sealed inside the choke body or other part of the branch, to prevent fluid communication between the first and second regions.
- the annulus between the conduit and the housing is closed so that the annulus is in communication with the branch only.
- the annulus has an outlet for connection to further pipes, so that the second region provides a flowpath which is separate from the first region formed by the bore of the conduit.
- first and second regions are connected by pipework.
- a processing apparatus is connected in the pipework so that fluids are processed whilst passing through the connecting pipework.
- the processing apparatus is chosen from at least one of: a pump; a process fluid turbine; injection apparatus for injecting gas or steam; chemical injection apparatus; a fluid riser; measurement apparatus; temperature measurement apparatus; flow rate measurement apparatus; constitution measurement apparatus; consistency measurement apparatus; gas separation apparatus; water separation apparatus; solids separation apparatus; and hydrocarbon separation apparatus.
- the diverter assembly provides a barrier to separate a branch outlet from a branch inlet.
- the barrier may separate a branch outlet from a production bore of a tree.
- the barrier comprises a plug, which is typically located inside the choke body (or other part of the manifold branch) to block the branch outlet.
- the plug is attached to the housing by a stem which extends axially through the internal passage of the housing.
- the barrier comprises a conduit of the diverter assembly which is engaged within the choke body or other part of the branch.
- the manifold is provided with a conduit connecting the first and second regions.
- a first set of fluids are recovered from a first well via a first diverter assembly and combined with other fluids in a communal conduit, and the combined fluids are then diverted into an export line via a second diverter assembly connected to a second well.
- a method of diverting fluids comprising: connecting a diverter assembly to a branch of a manifold, wherein the diverter assembly comprises a housing having an internal passage; and diverting the fluids through the housing.
- a method of diverting well fluids including the steps of:
- the diverter assembly is optionally located within a choke body; alternatively, the diverter assembly may be coupled in series with a choke.
- the diverter assembly may be located in the manifold branch adjacent to the choke, or it may be included within a separate extension portion of the manifold branch.
- the method is for recovering fluids from a well, and includes the final step of diverting fluids to an outlet of the first flowpath for recovery therefrom.
- the method is for injecting fluids into a well.
- the internal passage of the diverter assembly is in communication with the interior of the branch.
- the fluids may be passed in either direction through the diverter assembly.
- the diverter assembly includes separation means to provide two separate regions within the diverter assembly, and the method may includes the step of passing fluids through one or both of these regions.
- fluids are passed through the first and the second regions in the same direction.
- fluids are passed through the first and the second regions in opposite directions.
- the fluids are passed through one of the first and second regions and subsequently at least a proportion of these fluids are then passed through the other of the first and the second regions.
- the method includes the step of processing the fluids in a processing apparatus before passing the fluids back to the other of the first and second regions.
- fluids may be passed through only one of the two separate regions.
- the diverter assembly could be used to provide a connection between two flow paths which are unconnected to the well bore, e.g. between two external fluid lines.
- fluids could flow only through a region which is sealed from the branch.
- a flowpath could connect the bore of the conduit to a well bore (production or annulus bore) or another main bore of the tree to bypass the manifold branch. This flowpath could optionally link a region defined by the diverter assembly to a well bore via an aperture in the tree cap.
- first and second regions are connected by pipework.
- a processing apparatus is connected in the pipework so that fluids are processed whilst passing through the connecting pipework.
- the processing apparatus can be, but is not limited to, any of those described above.
- the method includes the step of removing a choke from the choke body before attaching the diverter assembly to the choke body.
- the method includes the step of diverting fluids from a first portion of a first flowpath to a second flowpath and diverting the fluids from the second flowpath to a second portion of the first flowpath.
- the first portion of the first flowpath is typically in communication with the production bore, and the second portion of the first flowpath is typically connected to a pipeline for carrying away the recovered fluids (e.g. to the surface).
- the first portion of the first flowpath is typically connected to an external fluid line, and the second portion of the first flowpath is in communication with the annulus bore.
- the flow directions may be reversed.
- the method provides the advantage that fluids can be diverted (e.g. recovered or injected into the well, or even diverted from another route, bypassing the well completely) without having to remove and replace any pipes already attached to the manifold branch outlet (e.g. a production wing branch outlet).
- manifold branch outlet e.g. a production wing branch outlet
- the method includes the step of recovering fluids from a well and the step of injecting fluids into the well.
- some of the recovered fluids are re-injected into the same well, or a different well.
- the production fluids could be separated into hydrocarbons and water; the hydrocarbons being returned to the first flowpath for recovery therefrom, and the water being returned and injected into the same or a different well.
- both of the steps of recovering fluids and injecting fluids include using respective flow diverter assemblies.
- only one of the steps of recovering and injecting fluids includes using a diverter assembly.
- the method includes the step of diverting the fluids through a processing apparatus.
- a manifold having a first diverter assembly according to the first aspect of the invention connected to a first branch and a second diverter assembly according to the first aspect of the invention connected to a second branch.
- the manifold comprises a tree and the first branch comprises a production wing branch and the second branch comprises an annulus wing branch.
- a manifold having a first bore having an outlet; a second bore having an outlet; a first diverter assembly connected to the first bore; a second diverter assembly connected to the second bore; and a flowpath connecting the first and second diverter assemblies.
- At least one of the first and second diverter assemblies blocks a passage in the manifold between a bore of the manifold and its respective outlet.
- the manifold comprises a tree
- the first bore comprises a production bore
- the second bore comprises an annulus bore.
- first and second diverter assemblies can be connected together to allow the unwanted parts of the produced fluids (e.g. water and sand) to be directly injected back into the well, instead of being pumped away with the hydrocarbons.
- the unwanted materials can be extracted from the hydrocarbons substantially at the wellhead, which reduces the quantity of production fluids to be pumped away, thereby saving energy.
- the first and second diverter assemblies can alternatively or additionally be used to connect to other kinds of processing apparatus (e.g. the types described with reference to other aspects of the invention), such as a booster pump, filter apparatus, chemical injection apparatus, etc. to allow adding or taking away of substances and adjustment of pressure to be carried out adjacent to the wellhead.
- the first and second diverter assemblies enable processing to be performed on both fluids being recovered and fluids being injected. Preferred embodiments of the invention enable both recovery and injection to occur simultaneously in the same well.
- the first and second diverter assemblies are connected to a processing apparatus.
- the processing apparatus can be any of those described with reference to other aspects of the invention.
- the diverter assembly may be a diverter assembly as described according to any aspect of the invention.
- a tubing system adapted to both recover and inject fluids is also provided.
- the tubing system is adapted to simultaneously recover and inject fluids.
- a method of recovery of fluids from, and injection of fluids into, a well wherein the well has a manifold that includes at least one bore and at least one branch having an outlet, the method including the steps of:
- the method is performed using a diverter assembly according to any aspect of the invention.
- a processing apparatus is coupled to the second flowpath.
- the processing apparatus can be any of the ones defined in any aspect of the invention.
- the processing apparatus separates hydrocarbons from the rest of the produced fluids.
- the non-hydrocarbon components of the produced fluids are diverted to the second diverter assembly to provide at least one component of the injection fluids.
- At least one component of the injection fluids is provided by an external fluid line which is not connected to the production bore or to the first diverter assembly.
- the method includes the step of diverting at least some of the injection fluids from a first portion of a first flowpath to a second flowpath and diverting the fluids from the second flowpath back to a second portion of the first flowpath for injection into the annulus bore of the well.
- the steps of recovering fluids from the well and injecting fluids into the well are carried out simultaneously.
- a well assembly comprising: a first well having a first diverter assembly; a second well having a second diverter assembly; and a flowpath connecting the first and second diverter assemblies.
- each of the first and second wells has a tree having a respective bore and a respective outlet, and at least one of the diverter assemblies blocks a passage in the tree between its respective tree bore and its respective tree outlet.
- an alternative outlet is provided, and the diverter assembly diverts fluids into a path leading to the alternative outlet.
- At least one of the first and second diverter assemblies is located within the production bore of its respective tree.
- at least one of the first and second diverter assemblies is connected to a wing branch of its respective tree.
- a method of diverting fluids from a first well to a second well via at least one manifold including the steps of:
- the at least one manifold comprises a tree of the first well and the method includes the further step of returning a portion of the recovered fluids to the tree of the first well and thereafter recovering that portion of the recovered fluids from the outlet of the blocked passage.
- a method of recovery of fluids from, and injection of fluids into, a well having a manifold wherein at least one of the steps of recovery and injection includes diverting fluids from a first portion of a first flowpath to a second flowpath and diverting the fluids from the second flowpath to a second portion of the first flowpath
- recovery and injection is simultaneous.
- some of the recovered fluids are re-injected into the well.
- a method of recovering fluids from a first well and re-injecting at least some of these recovered fluids into a second well wherein the method includes the steps of diverting fluids from a first portion of a first flowpath to a second flowpath, and diverting at least some of these fluids from the second flowpath to a second portion of the first flowpath.
- the fluids are recovered from the first well via a first diverter assembly, and wherein the fluids are re-injected into the second well via a second diverter assembly.
- the method also includes the step of processing the production fluids in a processing apparatus connected between the first and second wells.
- the method includes the further step of returning a portion of the recovered fluids to the first diverter assembly and thereafter recovering that portion of the recovered fluids via the first diverter assembly.
- a method of recovering fluids from, or injecting fluids into, a well including the step of diverting the fluids between a well bore and a branch outlet whilst bypassing at least a portion of the branch.
- Such embodiments are useful to divert fluids to a processing apparatus and then to return them to the wing branch outlet for recovery via a standard export line attached to the outlet.
- the method is also useful if a wing branch valve gets stuck shut.
- the fluids are diverted via the tree cap.
- a fourteenth aspect of the present invention there is provided a method of injecting fluids into a well, the method comprising diverting fluids from a first portion of a first flowpath to a second flowpath and diverting the fluids from the second flowpath into a second portion of the first flowpath.
- the method is performed using a diverter assembly according to any aspect of the invention.
- the diverter assembly may be locatable in a wide range of places, including, but not limited to: the production bore, the annulus bore, the production wing branch, the annulus wing branch, a production choke body, an annulus choke body, a tree cap or external conduits connected to a tree.
- the diverter assembly is not necessarily connected to a tree, but may instead be connected to another type of manifold.
- the first and second flowpaths could comprise some or all of any part of the manifold.
- the first flowpath is a production bore or production line, and the first portion of it is typically a lower part near to the wellhead.
- the first flowpath comprises an annulus bore.
- the second portion of the first flowpath is typically a downstream portion of the bore or line adjacent a branch outlet, although the first or second portions can be in the branch or outlet of the first flowpath.
- the diversion of fluids from the first flowpath allows the treatment of the fluids (e.g. with chemicals) or pressure boosting for more efficient recovery before re-entry into the first flowpath.
- the second flowpath is an annulus bore, or a conduit inserted into the first flowpath.
- Other types of bore may optionally be used for the second flowpath instead of an annulus bore.
- the flow diversion from the first flowpath to the second flowpath is achieved by a cap on the tree.
- the cap contains a pump or treatment apparatus, but this can be provided separately, or in another part of the apparatus, and in most embodiments of this type, flow will be diverted via the cap to the pump etc and returned to the cap by way of tubing.
- a connection typically in the form of a conduit is typically provided to transfer fluids between the first and second flowpaths.
- the diverter assembly can be formed from high grade steels or other metals, using e.g. resilient or inflatable sealing means as required.
- the assembly may include outlets for the first and second flowpaths, for diversion of the fluids to a pump or treatment assembly, or other processing apparatus as described in this application.
- the assembly optionally comprises a conduit capable of insertion into the first flowpath, the assembly having sealing means capable of sealing the conduit against the wall of the production bore.
- the conduit may provide a flow diverter through its central bore which typically leads to a Christmas tree cap and the pump mentioned previously.
- the seal effected between the conduit and the first flowpath prevents fluid from the first flowpath entering the annulus between the conduit and the production bore except as described hereinafter.
- the fluid After passing through a typical booster pump, squeeze or scale chemical treatment apparatus, the fluid is diverted into the second flowpath and from there to a crossover back to the first flowpath and first flowpath outlet.
- the assembly and method are typically suited for subsea production wells in normal mode or during well testing, but can also be used in subsea water injection wells, land based oil production injection wells, and geothermal wells.
- the pump can be powered by high pressure water or by electricity which can be supplied direct from a fixed or floating offshore installation, or from a tethered buoy arrangement, or by high pressure gas from a local source.
- the cap preferably seals within Christmas tree bores above the upper master valve. Seals between the cap and bores of the tree are optionally O-ring, inflatable, or preferably metal-to-metal seals.
- the cap can be retro-fitted very cost effectively with no disruption to existing pipework and minimal impact on control systems already in place.
- the typical design of the flow diverters within the cap can vary with the design of tree, the number, size, and configuration of the diverter channels being matched with the production and annulus bores, and others as the case may be. This provides a way to isolate the pump from the production bore if needed, and also provides a bypass loop.
- the cap is typically capable of retro-fitting to existing trees, and many include equivalent hydraulic fluid conduits for control of tree valves, and which match and co-operate with the conduits or other control elements of the tree to which the cap is being fitted.
- the cap has outlets for production and annulus flow paths for diversion of fluids away from the cap.
- a pump adapted to fit within a bore of a manifold.
- the manifold optionally comprises a tree, but can be any kind of manifold for an oil or gas well, such as a gathering manifold.
- a diverter assembly having a pump according to the fifteenth aspect of the present invention.
- the diverter assembly can be a diverter assembly according to any aspect of the invention, but it is not limited to these.
- the tree is typically a subsea tree, such as a Christmas tree, typically on a subsea well, but a topside tree (or other topside manifold) connected to a topside well could also be appropriate.
- a subsea tree such as a Christmas tree
- topside tree or other topside manifold connected to a topside well could also be appropriate.
- Horizontal or vertical trees are equally suitable for use of the invention.
- the bore of the tree may be a production bore.
- the diverter assembly and pump could be located in any bore of the tree, for example, in a wing branch bore.
- the flow diverter typically incorporates diverter means to divert fluids flowing through the bore of the tree from a first portion of the bore, through the pump, and back to a second portion of the bore for recovery therefrom via an outlet, which is typically the production wing valve.
- the first portion from which the fluids are initially diverted is typically the production bore/other bore/line of the well, and flow from this portion is typically diverted into a diverter conduit sealed within the bore.
- Fluid is typically diverted through the bore of the diverter conduit, and after passing therethrough, and exiting the bore of the diverter conduit, typically passes through the annulus created between the diverter conduit and the bore or line.
- the fluid passes through the pump internally of the tree, thereby minimising the external profile of the tree, and reducing the chances of damage to the pump.
- the pump is typically powered by a motor, and the type of motor can be chosen from several different forms.
- a hydraulic motor, a turbine motor or moineau motor can be driven by any well-known method, for example an electro-hydraulic power pack or similar power source, and can be connected, either directly or indirectly, to the pump.
- the motor can be an electric motor, powered by a local power source or by a remote power source.
- Certain embodiments of the present invention allow the construction of wellhead assemblies that can drive the fluid flow in different directions, simply by reversing the flow of the pump, although in some embodiments valves may need to be changed (e.g. reversed) depending on the design of the embodiment.
- the diverter assembly typically includes a tree cap that can be retrofitted to existing designs of tree, and can integrally contain the pump and/or the motor to drive it.
- the flow diverter preferably also comprises a conduit capable of insertion into the bore, and may have sealing means capable of sealing the conduit against the wall of the bore.
- the flow diverter typically seals within Christmas tree production bores above an upper master valve in a conventional tree, or in the tubing hangar of a horizontal tree, and seals can be optionally O-ring, inflatable, elastomeric or metal to metal seals.
- the cap or other parts of the flow diverter can comprise hydraulic fluid conduits.
- the pump can optionally be sealed within the conduit.
- a Christmas tree having a diverter assembly sealed in a bore of the tree, wherein the diverter assembly comprises a separator which divides the bore of the tree into two separate regions, and which extends through the tree bore and into the production zone of the well.
- the at least one diverter assembly comprises a conduit and at least one seal; the conduit optionally comprises a gas injection line.
- This invention may be used in conjunction with a further diverter assembly according to any other aspect of the invention, or with a diverter assembly in the form of a conduit which is sealed in the production bore.
- Both diverter assemblies may comprise conduits; one conduit may be arranged concentrically within the other conduit to provide concentric, separate regions within the production bore.
- a method of diverting fluids including the steps of:
- the injection fluids are typically gases; the method may include the steps of blocking a flowpath between the bore of the tree and a production wing outlet and diverting the recovered fluids out of the tree along an alternative route.
- the recovered fluids may be diverting the recovered fluids to a processing apparatus and returning at least some of these recovered fluids to the tree and recovering these fluids from a wing branch outlet.
- the recovered fluids may undergo any of the processes described in this invention, and may be returned to the tree for recovery, or not, (e.g. they may be recovered from a fluid riser) according to any of the described methods and flowpaths.
- FIG. 1 is a side sectional view of a typical production tree
- FIG. 2 is a side view of the FIG. 1 tree with a diverter cap in place;
- FIG. 3 a is a view of the FIG. 1 tree with a second embodiment of a cap in place;
- FIG. 3 b is a view of the FIG. 1 tree with a third embodiment of a cap in place;
- FIG. 4 a is a view of the FIG. 1 tree with a fourth embodiment of a cap in place;
- FIG. 4 b is a side view of the FIG. 1 tree with a fifth embodiment of a cap in place.
- FIG. 5 shows a side view of a first embodiment of a diverter assembly having an internal pump
- FIG. 6 shows a similar view of a second embodiment with an internal pump
- FIG. 7 shows a similar view of a third embodiment with an internal pump
- FIG. 8 shows a similar view of a fourth embodiment with an internal pump
- FIG. 9 shows a similar view of a fifth embodiment with an internal pump
- FIGS. 10 and 11 show a sixth embodiment with an internal pump
- FIGS. 12 and 13 show a seventh embodiment with an internal pump
- FIGS. 14 and 15 show an eighth embodiment with an internal pump
- FIG. 16 shows a ninth embodiment with an internal pump
- FIG. 17 shows a schematic diagram of the FIG. 2 embodiment coupled to processing apparatus
- FIG. 18 shows a schematic diagram of two embodiments of the invention engaged with a production well and an injection well respectively, the two wells being connected via a processing apparatus;
- FIG. 19 shows a specific example of the FIG. 18 embodiment
- FIG. 20 shows a cross-section of an alternative embodiment, which has a diverter conduit located inside a choke body
- FIG. 21 shows a cross-section of the embodiment of FIG. 20 located in a horizontal tree
- FIG. 22 shows a cross-section of a further embodiment, similar to the FIG. 20 embodiment, but also including a choke;
- FIG. 23 shows a cross-sectional view of a tree having a first diverter assembly coupled to a first branch of the tree and a second diverter assembly coupled to a second branch of the tree;
- FIG. 24 shows a schematic view of the FIG. 23 assembly used in conjunction with a first downhole tubing system
- FIG. 25 shows an alternative embodiment of a downhole tubing system which could be used with the FIG. 23 assembly
- FIGS. 26 and 27 show alternative embodiments of the invention, each having a diverter assembly coupled to a modified Christmas tree branch between a choke and a production wing valve;
- FIGS. 28 and 29 show further alternative embodiments, each having a diverter assembly coupled to a modified Christmas tree branch below a choke;
- FIG. 30 shows a first diverter assembly used to divert fluids from a first well and connected to an inlet header; and a second diverter assembly used to divert fluids from a second well and connected to an output header;
- FIG. 31 shows a cross-sectional view of an embodiment of a diverter assembly having a central stem
- FIG. 32 shows a cross-sectional view of an embodiment of a diverter assembly not having a central conduit
- FIG. 33 shows a cross-sectional view of a further embodiment of a diverter assembly
- FIG. 34 shows a cross-sectional view of a possible method of use of the FIG. 33 embodiment to provide a flowpath bypassing a wing branch of the tree;
- FIG. 35 shows a schematic diagram of a tree with a Christmas tree cap having a gas injection line
- FIG. 36 shows a more detailed view of the apparatus of FIG. 35 ;
- FIG. 37 shows a combination of the embodiments of FIGS. 3 and 35 ;
- FIG. 38 shows a further embodiment which is similar to FIG. 23 ;
- FIG. 39 shows a further embodiment which is similar to FIG. 18 .
- a typical production manifold on an offshore oil or gas wellhead comprises a Christmas tree with a production bore 1 leading from production tubing (not shown) and carrying production fluids from a perforated region of the production casing in a reservoir (not shown).
- An annulus bore 2 leads to the annulus between the casing and the production tubing and a Christmas tree cap 4 which seals off the production and annulus bores 1 , 2 , and provides a number of hydraulic control channels 3 by which a remote platform or intervention vessel can communicate with and operate the valves in the Christmas tree.
- the cap 4 is removable from the Christmas tree in order to expose the production and annulus bores in the event that intervention is required and tools need to be inserted into the production or annulus bores 1 , 2 .
- the flow of fluids through the production and annulus bores is governed by various valves shown in the typical tree of FIG. 1 .
- the production bore 1 has a branch 10 which is closed by a production wing valve (PWV) 12 .
- a production swab valve (PSV) 15 closes the production bore 1 above the branch 10 and PWV 12 .
- Two lower valves UPMV 17 and LPMV 18 (which is optional) close the production bore 1 below the branch 10 and PWV 12 .
- a crossover port (XOV) 20 is provided in the production bore 1 which connects to a the crossover port (XOV) 21 in annulus bore 2 .
- the annulus bore is closed by an annulus master valve (AMV) 25 below an annulus outlet 28 controlled by an annulus wing valve (AWV) 29 , itself below crossover port 21 .
- AMV annulus master valve
- AMV annulus wing valve
- the crossover port 21 is closed by crossover valve 30 .
- An annulus swab valve 32 located above the crossover port 21 closes the upper end of the annulus bore 2 .
- All valves in the tree are typically hydraulically controlled (with the exception of LPMV 18 which may be mechanically controlled) by means of hydraulic control channels 3 passing through the cap 4 and the body of the tool or via hoses as required, in response to signals generated from the surface or from an intervention vessel.
- LPMV 18 and UPMV 17 are opened, PSV 15 is closed, and PWV 12 is opened to open the branch 10 which leads to the pipeline (not shown). PSV 15 and ASV 32 are only opened if intervention is required.
- a wellhead cap 40 has a hollow conduit 42 with metal, inflatable or resilient seals 43 at its lower end which can seal the outside of the conduit 42 against the inside walls of the production bore 1 , diverting production fluids flowing in through branch 10 into the annulus between the conduit 42 and the production bore 1 and through the outlet 46 .
- Outlet 46 leads via tubing 216 to processing apparatus 213 (see FIG. 17 ).
- processing apparatus 213 could comprise a pump or process fluid turbine, for boosting the pressure of the fluid.
- the processing apparatus could inject gas, steam, sea water, drill cuttings or waste material into the fluids.
- the injection of gas could be advantageous, as it would give the fluids “lift”, making them easier to pump.
- the addition of steam has the effect of adding energy to the fluids.
- Injecting sea water into a well could be useful to boost the formation pressure for recovery of hydrocarbons from the well, and to maintain the pressure in the underground formation against collapse. Also, injecting waste gases or drill cuttings etc into a well obviates the need to dispose of these at the surface, which can prove expensive and environmentally damaging.
- the processing apparatus 213 could also enable chemicals to be added to the fluids, e.g. viscosity moderators, which thin out the fluids, making them easier to pump, or pipe skin friction moderators, which minimise the friction between the fluids and the pipes.
- Further examples of chemicals which could be injected are surfactants, refrigerants, and well fracturing chemicals.
- Processing apparatus 213 could also comprise injection water electrolysis equipment.
- the chemicals/injected materials could be added via one or more additional input conduits 214 .
- an additional input conduit 214 could be used to provide extra fluids to be injected.
- An additional input conduit 214 could, for example, originate from an inlet header (shown in FIG. 30 ).
- an additional outlet 212 could lead to an outlet header (also shown in FIG. 30 ) for recovery of fluids.
- the processing apparatus 213 could also comprise a fluid riser, which could provide an alternative route between the well bore and the surface. This could be very useful if, for example, the branch 10 becomes blocked.
- processing apparatus 213 could comprise separation equipment e.g. for separating gas, water, sand/debris and/or hydrocarbons.
- separation equipment e.g. for separating gas, water, sand/debris and/or hydrocarbons.
- the separated component(s) could be siphoned off via one or more additional process conduits 212 .
- the processing apparatus 213 could alternatively or additionally include measurement apparatus, e.g. for measuring the temperature/flow rate/constitution/consistency, etc. The temperature could then be compared to temperature readings taken from the bottom of the well to calculate the temperature change in produced fluids. Furthermore, the processing apparatus 213 could include injection water electrolysis equipment.
- the bore of conduit 42 can be closed by a cap service valve (CSV) 45 which is normally open but can close off an inlet 44 of the hollow bore of the conduit 42 .
- CSV cap service valve
- the conduit bore and the inlet 46 can also have an optional crossover valve (COV) designated 50 , and a tree cap adapter 51 in order to adapt the flow diverter channels in the tree cap 40 to a particular design of tree head.
- COV crossover valve
- Control channels 3 are mated with a cap controlling adapter 5 in order to allow continuity of electrical or hydraulic control functions from surface or an intervention vessel.
- This embodiment therefore provides a fluid diverter for use with a wellhead tree comprising a thin walled diverter conduit and a seal stack element connected to a modified Christmas tree cap, sealing inside the production bore of the Christmas tree typically above the hydraulic master valve, diverting flow through the conduit annulus, and the top of the Christmas tree cap and tree cap valves to typically a pressure boosting device or chemical treatment apparatus, with the return flow routed via the tree cap to the bore of the diverter conduit and to the well bore.
- a further embodiment of a cap 40 a has a large diameter conduit 42 a extending through the open PSV 15 and terminating in the production bore 1 having seal stack 43 a below the branch 10 , and a further seal stack 43 b sealing the bore of the conduit 42 a to the inside of the production bore 1 above the branch 10 , leaving an annulus between the conduit 42 a and bore 1 .
- Seals 43 a and 43 b are disposed on an area of the conduit 42 a with reduced diameter in the region of the branch 10 .
- Seals 43 a and 43 b are also disposed on either side of the crossover port 20 communicating via channel 21 c to the crossover port 21 of the annulus bore 2 .
- Injection fluids enter the branch 10 from where they pass into the annulus between the conduit 42 a and the production bore 1 . Fluid flow in the axial direction is limited by the seals 43 a , 43 b and the fluids leave the annulus via the crossover port 20 into the crossover channel 21 c .
- the crossover channel 21 c leads to the annulus bore 2 and from there the fluids pass through the outlet 62 to the pump or chemical treatment apparatus.
- the treated or pressurised fluids are returned from the pump or treatment apparatus to inlet 61 in the production bore 1 .
- the fluids travel down the bore of the conduit 42 a and from there, directly into the well bore.
- Cap service valve (CSV) 60 is normally open, annulus swab valve 32 is normally held open, annulus master valve 25 and annulus wing valve 29 are normally closed, and crossover valve 30 is normally open.
- a crossover valve 65 is provided between the conduit bore 42 a and the annular bore 2 in order to bypass the pump or treatment apparatus if desired. Normally the crossover valve 65 is maintained closed.
- This embodiment maintains a fairly wide bore for more efficient recovery of fluids at relatively high pressure, thereby reducing pressure drops across the apparatus.
- This embodiment therefore provides a fluid diverter for use with a manifold such as a wellhead tree comprising a thin walled diverter with two seal stack elements, connected to a tree cap, which straddles the crossover valve outlet and flowline outlet (which are approximately in the same horizontal plane), diverting flow from the annular space between the straddle and the existing xmas tree bore, through the crossover loop and crossover outlet, into the annulus bore (or annulus flowpath in concentric trees), to the top of the tree cap to pressure boosting or chemical treatment apparatus etc, with the return flow routed via the tree cap and the bore of the conduit.
- a manifold such as a wellhead tree
- straddles the crossover valve outlet and flowline outlet which are approximately in the same horizontal plane
- FIG. 3 b shows a simplified version of a similar embodiment, in which the conduit 42 a is replaced by a production bore straddle 70 having seals 73 a and 73 b having the same position and function as seals 43 a and 43 b described with reference to the FIG. 3 a embodiment.
- production fluids enter via the branch 10 , pass through the open valve PWV 12 into the annulus between the straddle 70 and the production bore 1 , through the channel 21 c and crossover port 20 , through the outlet 62 a to be treated or pressurised etc, and the fluids are then returned via the inlet 61 a , through the straddle 70 , through the open LPMV 18 and UPMV 17 to the production bore 1 .
- This embodiment therefore provides a fluid diverter for use with a manifold such as a wellhead tree which is not connected to the tree cap by a thin walled conduit, but is anchored in the tree bore, and which allows full bore flow above the “straddle” portion, but routes flow through the crossover and will allow a swab valve (PSV) to function normally.
- a manifold such as a wellhead tree which is not connected to the tree cap by a thin walled conduit, but is anchored in the tree bore, and which allows full bore flow above the “straddle” portion, but routes flow through the crossover and will allow a swab valve (PSV) to function normally.
- PSV swab valve
- the FIG. 4 a embodiment has a different design of cap 40 c with a wide bore conduit 42 c extending down the production bore 1 as previously described.
- the conduit 42 c substantially fills the production bore 1 , and at its distal end seals the production bore at 83 just above the crossover port 20 , and below the branch 10 .
- the PSV 15 is, as before, maintained open by the conduit 42 c , and perforations 84 at the lower end of the conduit are provided in the vicinity of the branch 10 .
- Crossover valve 65 b is provided between the production bore 1 and annulus bore 2 in order to bypass the chemical treatment or pump as required.
- FIG. 4 a embodiment works in a similar way to the previous embodiments.
- This embodiment therefore provides a fluid diverter for use with a wellhead tree comprising a thin walled conduit connected to a tree cap, with one seal stack element, which is plugged at the bottom, sealing in the production bore above the hydraulic master valve and crossover outlet (where the crossover outlet is below the horizontal plane of the flowline outlet), diverting flow through the branch to the annular space between the perforated end of the conduit and the existing tree bore, through perforations 84 , through the bore of the conduit 42 , to the tree cap, to a treatment or booster apparatus, with the return flow routed through the annulus bore (or annulus flow path in concentric trees) and crossover outlet, to the production bore 1 and the well bore.
- a modified embodiment dispenses with the conduit 42 c of the FIG. 4 a embodiment, and simply provides a seal 83 a above the XOV port 20 and below the branch 10 .
- This embodiment works in the same way as the previous embodiments.
- This embodiment provides a fluid diverter for use with a manifold such as a wellhead tree which is not connected to the tree cap by a thin walled conduit, but is anchored in the tree bore and which routes the flow through the crossover and allows full bore flow for the return flow, and will allow the swab valve to function normally.
- a manifold such as a wellhead tree which is not connected to the tree cap by a thin walled conduit, but is anchored in the tree bore and which routes the flow through the crossover and allows full bore flow for the return flow, and will allow the swab valve to function normally.
- FIG. 5 shows a subsea tree 101 having a production bore 123 for the recovery of production fluids from the well.
- the tree 101 has a cap body 103 that has a central bore 103 b , and which is attached to the tree 101 so that the bore 103 b of the cap body 103 is aligned with the production bore 123 of the tree.
- Flow of production fluids through the production bore 123 is controlled by the tree master valve 112 , which is normally open, and the tree swab valve 114 , which is normally closed during the production phase of the well, so as to divert fluids flowing through the production bore 123 and the tree master valve 112 , through the production wing valve 113 in the production branch, and to a production line for recovery as is conventional in the art.
- the bore 103 b of the cap body 103 contains a turbine or turbine motor 108 mounted on a shaft that is journalled on bearings 122 .
- the shaft extends continuously through the lower part of the cap body bore 103 b and into the production bore 123 at which point, a turbine pump, centrifugal pump or, as shown here a turbine pump 107 is mounted on the same shaft.
- the turbine pump 107 is housed within a conduit 102 .
- the turbine motor 108 is configured with inter-collating vanes 108 v and 103 v on the shaft and side walls of the bore 103 b respectively, so that passage of fluid past the vanes in the direction of the arrows 126 a and 126 b turns the shaft of the turbine motor 108 , and thereby turns the vanes of the turbine pump 107 , to which it is directly connected.
- the bore of the conduit 102 housing the turbine pump 107 is open to the production bore 123 at its lower end, but there is a seal between the outer face of the conduit 102 and the inner face of the production bore 123 at that lower end, between the tree master valve 112 and the production wing branch, so that all production fluid passing through the production bore 123 is diverted into the bore of the conduit 102 .
- the seal is typically an elastomeric or a metal to metal seal.
- the upper end of the conduit 102 is sealed in a similar fashion to the inner surface of the cap body bore 103 b , at a lower end thereof, but the conduit 102 has apertures 102 a allowing fluid communication between the interior of the conduit 102 , and the annulus 124 , 125 formed between the conduit 102 and the bore of the tree.
- the turbine motor 108 is driven by fluid propelled by a hydraulic power pack H which typically flows in the direction of arrows 126 a and 126 b so that fluid forced down the bore 103 b of the cap turns the vanes 108 v of the turbine motor 108 relative to the vanes 103 v of the bore, thereby turning the shaft and the turbine pump 107 .
- These actions draw fluid from the production bore 123 up through the inside of the conduit 102 and expels the fluid through the apertures 102 a , into the annulus 124 , 125 of the production bore.
- conduit 102 Since the conduit 102 is sealed to the bore above the apertures 102 a , and below the production wing branch at the lower end of the conduit 102 , the fluid flowing into the annulus 124 is diverted through the annulus 125 and into the production wing through the production wing valve 113 and can be recovered by normal means.
- Another benefit of the present embodiment is that the direction of flow of the hydraulic power pack H can be reversed from the configuration shown in FIG. 5 , and in such case the fluid flow would be in the reverse direction from that shown by the arrows in FIG. 5 , which would allow the re-injection of fluid from the production wing valve 113 , through the annulus 125 , 124 aperture 102 a , conduit 102 and into the production bore 123 , all powered by means of the pump 107 and motor 108 operating in reverse. This can allow water injection or injection of other chemicals or substances into all kinds of wells.
- any suitable turbine or moineau motor can be used, and can be powered by any well known method, such as the electro-hydraulic power pack shown in FIG. 5 , but this particular source of power is not essential to the invention.
- FIG. 6 shows a different embodiment that uses an electric motor 104 instead of the turbine motor 108 to rotate the shaft and the turbine pump 107 .
- the electric motor 104 can be powered from an external or a local power source, to which it is connected by cables (not shown) in a conventional manner.
- the electric motor 104 can be substituted for a hydraulic motor or air motor as required.
- the direction of rotation of the shaft can be varied by changing the direction of operation of the motor 104 , so as to change the direction of flow of the fluid by the arrows in FIG. 6 to the reverse direction.
- the FIG. 6 assembly can be retrofitted to existing designs of Christmas trees, and can be fitted to many different tree bore diameters.
- the embodiments described can also be incorporated into new designs of Christmas tree as integral features rather than as retrofit assemblies.
- the embodiments can be fitted to other kinds of manifold apart from trees, such as gathering manifolds, on subsea or topside wells.
- FIG. 7 shows a further embodiment which illustrates that the connection between the shafts of the motor and the pump can be direct or indirect.
- the electrical motor 104 powers a drive belt 109 , which in turn powers the shaft of the pump 107 .
- This connection between the shafts of the pump and motor permits a more compact design of cap 103 .
- the drive belt 109 illustrates a direct mechanical type of connection, but could be substituted for a chain drive mechanism, or a hydraulic coupling, or any similar indirect connector such as a hydraulic viscous coupling or well known design.
- FIG. 7 embodiment can be operated in reverse to draw fluids in the opposite direction of the arrows shown, if required to inject fluids such as water, chemicals for treatment, or drill cuttings for disposal into the well.
- FIG. 8 shows a further modified embodiment using a hollow turbine shaft 102 s that draws fluid from the production bore 123 through the inside of conduit 102 and into the inlet of a combined motor and pump unit 105 , 107 .
- the motor/pump unit has a hollow shaft design, where the pump rotor 107 r is arranged concentrically inside the motor rotor 105 r , both of which are arranged inside a motor stator 105 s .
- the pump rotor 107 r and the motor rotor 105 r rotate as a single piece on bearings 122 around the static hollow shaft 102 s thereby drawing fluid from the inside of the shaft 102 through the upper apertures 102 u , and down through the annulus 124 between the shaft 102 s and the bore 103 b of the cap 103 .
- the lower portion of the shaft 102 s is apertured at 1021 , and the outer surface of the conduit 102 is sealed within the bore of the shaft 102 s above the lower aperture 1021 , so that fluid pumped from the annulus 124 and entering the apertures 1021 , continues flowing through the annulus 125 between the conduit 102 and the shaft 102 s into the production bore 123 , and finally through the production wing valve 113 for export as normal.
- the motor can be any prime mover of hollow shaft construction, but electric or hydraulic motors can function adequately in this embodiment.
- the pump design can be of any suitable type, but a moineau motor, or a turbine as shown here, are both suitable.
- the direction of flow of fluid through the pump shown in FIG. 8 can be reversed simply by reversing the direction of the motor, so as to drive the fluid in the opposite direction of the arrows shown in FIG. 8 .
- this embodiment employs a motor 106 in the form of a disc rotor that is preferably electrically powered, but could be hydraulic or could derive power from any other suitable source, connected to a centrifugal disc-shaped pump 107 that draws fluid from the production bore 123 through the inner bore of the conduit 102 and uses centrifugal impellers to expel the fluid radially outwards into collecting conduits 124 , and thence into an annulus 125 formed between the conduit 102 and the production bore 123 in which it is sealed.
- the fluid propelled down the annulus 125 cannot pass the seal at the lower end of the conduit 102 below the production wing branch, and exits through the production wing valve 113 .
- FIG. 9 b shows the same pump configured to operate in reverse, to draw fluids through the production wing valve 113 , into the conduit 125 , across the pump 107 , through the re-routed conduit 124 ′ and conduit 102 , and into the production bore 123 .
- FIG. 9 design One advantage of the FIG. 9 design is that the disc shaped motor and pump illustrated therein can be duplicated to provide a multi-stage pump with several pump units connected in series and/or in parallel in order to increase the pressure at which the fluid is pumped through the production wing valve 113 .
- this embodiment illustrates a piston 115 that is sealed within the bore 103 b of the cap 103 , and connected via a rod to a further lower piston assembly 116 within the bore of the conduit 102 .
- the conduit 102 is again sealed within the bore 103 b and the production bore 123 .
- the lower end of the piston assembly 116 has a check valve 119 .
- the piston 115 is moved up from the lower position shown in FIG. 10 a by pumping fluid into the aperture 126 a through the wall of the bore 103 b by means of a hydraulic power pack in the direction shown by the arrows in FIG. 10 a .
- the piston annulus is sealed below the aperture 126 a , and so a build-up of pressure below the piston pushes it upward towards the aperture 126 b , from which fluid is drawn by the hydraulic power pack.
- a hydraulic signal 130 is generated that controls the valve 117 , to maintain the direction of the fluid flow shown in FIG. 10 a .
- the check valve 119 in the lower piston assembly 116 closes, trapping the fluid in the annulus 124 above the lower piston assembly 116 .
- the valve 117 switches, causing the piston 115 to rise again and pull the lower piston assembly 116 with it.
- the fluid driven by the hydraulic power pack can be driven by other means.
- linear oscillating motion can be imparted to the lower piston assembly 116 by other well-known methods i.e. rotating crank and connecting rod, scotch yolk mechanisms etc.
- FIGS. 10 and 11 embodiment can be retrofitted to existing trees of varying diameters or incorporated into the design of new trees.
- a further embodiment has a similar piston arrangement as the embodiment shown in FIGS. 10 and 11 , but the piston assembly 115 , 116 is housed within a cylinder formed entirely by the bore 103 b of the cap 103 .
- drive fluid is pumped by the hydraulic power pack into the chamber below the upper piston 115 , causing it to rise as shown in FIG. 12 a , and the signal line 130 keeps the valve 117 in the correct position as the piston 115 is rising.
- This draws well fluid through the conduit 102 and check valve 119 into the chamber formed in the cap bore 103 b .
- the signal line 131 is triggered to switch the valve 117 to the position shown in FIG.
- FIGS. 14 and 15 A further embodiment is shown in FIGS. 14 and 15 , which works in a similar fashion but has a short diverter assembly 102 sealed to the production bore and straddling the production wing branch.
- the lower piston 116 strokes in the production bore 123 above the diverter assembly 102 .
- the drive fluid raises the piston 115 in a first phase shown in FIG. 14 , drawing well fluid through the check valve 119 , through the diverter assembly 102 and into the upper portion of the production bore 123 .
- the valve 117 switches to the configuration shown in FIG. 15 , the pistons 115 , 116 are driven down, thereby expelling the well fluids trapped in the bore 123 u , through the check valve 120 (valve 119 is closed) and the production wing valve 113 .
- FIG. 16 shows a further embodiment, which employs a rotating crank 110 with an eccentrically attached arm 110 a instead of a fluid drive mechanism to move the piston 116 .
- the crank 110 is pulling the piston upward when in the position shown in FIG. 16 a , and pushing it downward when in the position shown in 16 b . This draws fluid into the upper part of the production bore 123 u as previously described.
- the straddle 102 and check valve arrangements as described in the previous embodiment.
- the pump does not have to be located in a production bore; the pump could be located in any bore of the tree with an inlet and an outlet.
- the pump and diverter assembly may be connected to a wing branch of a tree/a choke body as shown in other embodiments of the invention.
- FIG. 18 shows a general arrangement, whereby a production well 230 and an injection well 330 are connected together via processing apparatus 220 .
- the injection well 330 can be any of the capped production well embodiments described above.
- the production well 230 can also be any of the abovedescribed production well embodiments, with outlets and inlets reversed.
- Produced fluids from production well 230 flow up through the bore of conduit 42 , exit via outlet 244 , and pass through tubing 232 to processing apparatus 220 , which may also have one or more further input lines 222 and one or more further outlet lines 224 .
- Processing apparatus 220 can be selected to perform any of the functions described above with reference to processing apparatus 213 in the FIG. 17 embodiment. Additionally, processing apparatus 220 can also separate water/gas/oil/sand/debris from the fluids produced from production well 230 and then inject one or more of these into injection well 330 . Separating fluids from one well and re-injecting into another well via subsea processing apparatus 220 reduces the quantity of tubing, time and energy necessary compared to performing each function individually as described with respect to the FIG. 17 embodiment. Processing apparatus 220 may also include a riser to the surface, for carrying the produced fluids or a separated component of these to the surface.
- Tubing 233 connects processing apparatus 220 back to an inlet 246 of a wellhead cap 240 of production well 230 .
- the processing apparatus 220 could also be used to inject gas into the separated hydrocarbons for lift and also for the injection of any desired chemicals such as scale or wax inhibitors.
- the hydrocarbons are then returned via tubing 233 to inlet 246 and flow from there into the annulus between the conduit 42 and the bore in which it is disposed. As the annulus is sealed at the upper and lower ends, the fluids flow through the export line 210 for recovery.
- the horizontal line 310 of injection well 330 serves as an injection line (instead of an export line). Fluids to be injected can enter injection line 310 , from where they pass via the annulus between the conduit 42 and the bore to the tree cap outlet 346 and tubing 235 into processing apparatus 220 .
- the processing apparatus may include a pump, chemical injection device, and/or separating devices, etc.
- processing apparatus 220 includes a riser, this riser could be used to transport the processed produced fluids to the surface, instead of passing them back down into the Christmas tree of the production bore again for recovery via export line 210 .
- FIG. 19 shows a specific example of the more general embodiment of FIG. 18 and like numbers are used to designate like parts.
- the processing apparatus in this embodiment includes a water injection booster pump 260 connected via tubing 235 to an injection well, a production booster pump 270 connected via tubing 232 to a production well, and a water separator vessel 250 , connected between the two wells via tubing 232 , 233 and 234 .
- Pumps 260 , 270 are powered by respective high voltage electricity power umbilicals 265 , 275 .
- produced fluids from production well 230 exit as previously described via conduit 42 (not shown in FIG. 19 ), outlet 244 and tubing 232 ; the pressure of the fluids are boosted by booster pump 270 .
- the produced fluids then pass into separator vessel 250 , which separates the hydrocarbons from the produced water.
- the hydrocarbons are returned to production well cap 240 via tubing 233 ; from cap 240 , they are then directed via the annulus surrounding the conduit 42 to export line 210 .
- the separated water is transferred via tubing 234 to the wellbore of injection well 330 via inlet 344 .
- the separated water enters injection well through inlet 344 , from where it passes directly into its conduit 42 and from there, into the production bore and the depths of injection well 330 .
- injection well 330 it may also be desired to inject additional fluids into injection well 330 .
- This can be done by closing a valve in tubing 234 to prevent any fluids from entering the injection well via tubing 234 .
- these additional fluids can enter injection well 330 via injection line 310 (which was formerly the export line in previous embodiments). The rest of this procedure will follow that described above with reference to FIG. 17 .
- Fluids entering injection line 310 pass up the annulus between conduit 42 (see FIGS. 2 and 17 ) and the wellbore, are diverted by the seals 43 (see FIG. 2 ) at the lower end of conduit 42 to travel up the annulus, and exit via outlet 346 .
- the fluids then pass along tubing 235 , are pressure boosted by booster pump 260 and are returned via conduit 237 to inlet 344 of the Christmas tree. From here, the fluids pass through the inside of conduit 42 and directly into the wellbore and the depths of the well 330 .
- fluids are injected into injection well 330 from tubing 234 (i.e. fluids separated from the produced fluids of production well 230 ) and from injection line 310 (i.e. any additional fluids) in sequence.
- tubings 234 and 237 could combine at inlet 344 and the two separate lines of injected fluids could be injected into well 330 simultaneously.
- the processing apparatus could comprise simply the water separator vessel 250 , and not include either of the booster pumps 260 , 270 .
- FIGS. 18 and 19 Although only two connected wells are shown in FIGS. 18 and 19 , it should be understood that more wells could also be connected to the processing apparatus.
- FIGS. 20 and 21 Two further embodiments of the invention are shown in FIGS. 20 and 21 ; these embodiments are adapted for use in a traditional and horizontal tree respectively. These embodiments have a diverter assembly 502 located partially inside a Christmas tree choke body 500 . (The internal parts of the choke have been removed, just leaving choke body 500 ). Choke body 500 communicates with an interior bore of a perpendicular extension of branch 10 .
- Diverter assembly 502 comprises a housing 504 , a conduit 542 , an inlet 546 and an outlet 544 .
- Housing 504 is substantially cylindrical and has an axial passage 508 extending along its entire length and a connecting lateral passage adjacent to its upper end; the lateral passage leads to outlet 544 .
- the lower end of housing 504 is adapted to attach to the upper end of choke body 500 at clamp 506 .
- Axial passage 508 has a reduced diameter portion at its upper end; conduit 542 is located inside axial passage 508 and extends through axial passage 508 as a continuation of the reduced diameter portion.
- conduit 542 extends beyond housing 504 into choke body 500 , and past the junction between branch 10 and its perpendicular extension. At this point, the perpendicular extension of branch 10 becomes an outlet 530 of branch 10 ; this is the same outlet as shown in the FIG. 2 embodiment. Conduit 542 is sealed to the perpendicular extension at seal 532 just below the junction. Outlet 544 and inlet 546 are typically attached to conduits (not shown) which leads to and from processing apparatus, which could be any of the processing apparatus described above with reference to previous embodiments.
- the diverter assembly 502 can be used to recover fluids from or inject fluids into a well. A method of recovering fluids will now be described.
- produced fluids come up the production bore 1 , enter branch 10 and from there enter annulus 520 between conduit 542 and axial passage 508 .
- the fluids are prevented from going downwards towards outlet 530 by seal 532 , so they are forced upwards in annulus 520 , exiting annulus 520 via outlet 544 .
- Outlet 544 typically leads to a processing apparatus (which could be any of the ones described earlier, e.g. a pumping or injection apparatus).
- a processing apparatus which could be any of the ones described earlier, e.g. a pumping or injection apparatus.
- FIGS. 20 and 21 can be used with the flow directions reversed.
- FIG. 20 and FIG. 21 tree embodiments have the advantage that the diverter assembly can be integrated easily with the existing choke body with minimal intervention in the well; locating a part of the diverter assembly in the choke body need not even involve removing well cap 40 .
- FIG. 22 A further embodiment is shown in FIG. 22 . This is very similar to the FIGS. 20 and 21 embodiments, with a choke 540 coupled (e.g. clamped) to the top of choke body 500 . Like parts are designated with like reference numerals. Choke 540 is a standard subsea choke.
- Outlet 544 is coupled via a conduit (not shown) to processing apparatus 550 , which is in turn connected to an inlet of choke 540 .
- Choke 540 is a standard choke, having an inner passage with an outlet at its lower end and an inlet 541 .
- the lower end of passage 540 is aligned with inlet 546 of axial passage 508 of housing 504 ; thus the inner passage of choke 540 and axial passage 508 collectively form one combined axial passage.
- produced fluids from production bore 1 enter branch 10 and from there enter annulus 520 between conduit 542 and axial passage 508 .
- the fluids are prevented from going downwards towards outlet 530 by seal 532 , so they are forced upwards in annulus 520 , exiting annulus 520 via outlet 544 .
- Outlet 544 typically leads to a processing apparatus (which could be any of the ones described earlier, e.g. a pumping or injection apparatus).
- a processing apparatus which could be any of the ones described earlier, e.g. a pumping or injection apparatus.
- Choke 540 may be opened, or partially opened as desired to control the pressure of the produced fluids.
- the produced fluids pass through the inner passage of the choke, through conduit 542 and exit though outlet 530 , from where they are recovered via an export line.
- FIG. 22 embodiment is useful for embodiments which also require a choke in addition to the diverter assembly of FIGS. 20 and 21 .
- the FIG. 22 embodiment can be used to inject fluids into a well by reversing the flow paths.
- Conduit 542 does not necessarily form an extension of axial passage 508 .
- Alternative embodiments could include a conduit which is a separate component to housing 504 ; this conduit could be sealed to the upper end of axial passage 508 above outlet 544 , in a similar way as conduit 542 is sealed at seal 532 .
- Embodiments of the invention can be retrofitted to many different existing designs of manifold, by simply matching the positions and shapes of the hydraulic control channels 3 in the cap, and providing flow diverting channels or connected to the cap which are matched in position (and preferably size) to the production, annulus and other bores in the tree or other manifold.
- a conventional tree manifold 601 is illustrated having a production bore 602 and an annulus bore 603 .
- the tree has a production wing 620 and associated production wing valve 610 .
- the production wing 620 terminates in a production choke body 630 .
- the production choke body 630 has an interior bore 607 extending therethrough in a direction perpendicular to the production wing 620 .
- the bore 607 of the production choke body is in communication with the production wing 620 so that the choke body 630 forms an extension portion of the production wing 620 .
- the opening at the lower end of the bore 607 comprises an outlet 612 .
- a choke is usually installed in the production choke body 630 , but in the tree 601 of the present invention, the choke itself has been removed.
- the tree 601 also has an annulus wing 621 , an annulus wing valve 611 , an annulus choke body 631 and an interior bore 609 of the annulus choke body 631 terminating in an inlet 613 at its lower end. There is no choke inside the annulus choke body 631 .
- a first diverter assembly 604 Attached to the production choke body 630 of the production wing 620 is a first diverter assembly 604 in the form of a production insert.
- the diverter assembly 604 is very similar to the flow diverter assemblies of FIGS. 20 to 22 .
- the production insert 604 comprises a substantially cylindrical housing 640 , a conduit 642 , an inlet 646 and an outlet 644 .
- the housing 640 has a reduced diameter portion 641 at an upper end and an increased diameter portion 643 at a lower end.
- the conduit 642 has an inner bore 649 , and forms an extension of the reduced diameter portion 641 .
- the conduit 642 is longer than the housing 640 so that it extends beyond the end of the housing 640 .
- the space between the outer surface of the conduit 642 and the inner surface of the housing 640 forms an axial passage 647 , which ends where the conduit 642 extends out from the housing 640 .
- a connecting lateral passage is provided adjacent to the join of the conduit 642 and the housing 640 ; the lateral passage is in communication with the axial passage 647 of the housing 640 and terminates in the outlet 644 .
- the lower end of the housing 640 is attached to the upper end of the production choke body 630 at a clamp 648 .
- the conduit 642 is sealingly attached inside the inner bore 607 of the choke body 630 at an annular seal 645 .
- the second diverter assembly 605 is of the same form as the first diverter assembly 604 .
- the components of the second diverter assembly 605 are the same as those of the first diverter assembly 604 , including a housing 680 comprising a reduced diameter portion 681 and an enlarged diameter portion 683 ; a conduit 682 extending from the reduced diameter portion 681 and having a bore 689 ; an outlet 686 ; an inlet 684 ; and an axial passage 687 formed between the enlarged diameter portion 683 of the housing 680 and the conduit 682 .
- a connecting lateral passage is provided adjacent to the join of the conduit 682 and the housing 680 ; the lateral passage is in communication with the axial passage 687 of the housing 680 and terminates in the inlet 684 .
- the housing 680 is clamped by a clamp 688 on the annulus choke body 631 , and the conduit 682 is sealed to the inside of the annulus choke body 631 at seal 685 .
- a conduit 690 connects the outlet 644 of the first diverter assembly 604 to a processing apparatus 700 .
- the processing apparatus 700 comprises bulk water separation equipment, which is adapted to separate water from hydrocarbons.
- a further conduit 692 connects the inlet 646 of the first diverter assembly 604 to the processing apparatus 700 .
- conduits 694 , 696 connect the outlet 686 and the inlet 684 respectively of the second diverter assembly 605 to the processing apparatus 700 .
- the processing apparatus 700 has pumps 820 fitted into the conduits between the separation vessel and the first and second flow diverter assemblies 604 , 605 .
- the production bore 602 and the annulus bore 603 extend down into the well from the tree 601 , where they are connected to a tubing system 800 a , shown in FIG. 24 .
- the tubing system 800 a is adapted to allow the simultaneous injection of a first fluid into an injection zone 805 and production of a second fluid from a production zone 804 .
- the tubing system 800 a comprises an inner tubing 810 which is located inside an outer tubing 812 .
- the production bore 602 is the inner bore of the inner tubing 810 .
- the inner tubing 810 has perforations 814 in the region of the production zone 804 .
- the outer tubing has perforations 816 in the region of the injection zone 805 .
- a cylindrical plug 801 is provided in the annulus bore 603 which lies between the outer tubing 812 and the inner tubing 810 . The plug 801 separates the part of the annulus bore 803 in the region of the injection zone 805 from the rest of the annulus bore 803 .
- the produced fluids (typically a mixture of hydrocarbons and water) enter the inner tubing 810 through the perforations 814 and pass into the production bore 602 .
- the produced fluids then pass through the production wing 620 , the axial passage 647 , the outlet 644 , and the conduit 690 into the processing apparatus 700 .
- the processing apparatus 700 separates the hydrocarbons from the water (and optionally other elements such as sand), e.g. using centrifugal separation.
- the processing apparatus can comprise any of the types of processing apparatus mentioned in this specification.
- the separated hydrocarbons flow into the conduit 692 , from where they return to the first diverter assembly 604 via the inlet 646 .
- the hydrocarbons then flow down through the conduit 642 and exit the choke body 630 at outlet 612 , e.g. for removal to the surface.
- the water separated from the hydrocarbons by the processing apparatus 700 is diverted through the conduit 696 , the axial passage 687 , and the annulus wing 611 into the annulus bore 603 .
- the water passes through the perforations 816 in the outer tubing 812 into the injection zone 805 .
- extra fluids can be injected into the well in addition to the separated water. These extra fluids flow into the second diverter assembly 631 via the inlet 613 , flow directly through the conduit 682 , the conduit 694 and into the processing apparatus 700 . These extra fluids are then directed back through the conduit 696 and into the annulus bore 603 as explained above for the path of the separated water.
- FIG. 25 shows an alternative form of tubing system 800 b including an inner tubing 820 , an outer tubing 822 and an annular seal 821 , for use in situations where a production zone 824 is located above an injection zone 825 .
- the inner tubing 820 has perforations 836 in the region of the production zone 824 and the outer tubing 822 has perforations 834 in the region of the injection zone 825 .
- the outer tubing 822 which generally extends round the circumference of the inner tubing 820 , is split into a plurality of axial tubes in the region of the production zone 824 . This allows fluids from the production zone 824 to pass between the axial tubes and through the perforations 836 in the inner tubing 820 into the production bore 602 . From the production bore 602 the fluids pass upwards into the tree as described above. The returned injection fluids in the annulus bore 603 pass through the perforations 834 in the outer tubing 822 into the injection zone 825 .
- the FIG. 23 embodiment does not necessarily include any kind of processing apparatus 700 .
- the FIG. 23 embodiment may be used to recover fluids and/or inject fluids, either at the same time, or different times.
- the fluids to be injected do not necessarily have to originate from any recovered fluids; the injected fluids and recovered fluids may instead be two un-related streams of fluids. Therefore, the FIG. 23 embodiment does not have to be used for re-injection of recovered fluids; it can additionally be used in methods of injection.
- the pumps 820 are optional.
- the tubing system 800 a , 800 b could be any system that allows both production and injection; the system is not limited to the examples given above.
- the tubing system could comprise two conduits which are side by side, instead of one inside the other, one of the conduits providing the production bore and the second providing the annulus bore.
- FIGS. 26 to 29 illustrate alternative embodiments where the diverter assembly is not inserted within a choke body. These embodiments therefore allow a choke to be used in addition to the diverter assembly.
- FIG. 26 shows a manifold in the form of a tree 900 having a production bore 902 , a production wing branch 920 , a production wing valve 910 , an outlet 912 and a production choke 930 .
- the production choke 930 is a full choke, fitted as standard in many Christmas trees, in contrast with the production choke body 630 of the FIG. 23 embodiment, from which the actual choke has been removed. In FIG. 26 , the production choke 930 is shown in a fully open position.
- a diverter assembly 904 in the form of a production insert is located in the production wing branch 920 between the production wing valve 910 and the production choke 930 .
- the diverter assembly 904 is the same as the diverter assembly 604 of the FIG. 23 embodiment, and like parts are designated here by like numbers, prefixed by “9”.
- the FIG. 26 housing 940 is attached to the production wing branch 920 at a clamp 948 .
- the lower end of the conduit 942 is sealed inside the production wing branch 920 at a seal 945 .
- the production wing branch 920 includes a secondary branch 921 which connects the part of the production wing branch 920 adjacent to the diverter assembly 904 with the part of the production wing branch 920 adjacent to the production choke 930 .
- a valve 922 is located in the production wing branch 920 between the diverter assembly 904 and the production choke 930 .
- valve 922 and the seal 945 prevents production fluids from flowing directly from the production bore 902 to the outlet 912 . Instead, the production fluids are diverted into the axial annular passage 947 between the conduit 942 and the housing 940 . The fluids then exit the outlet 944 into a processing apparatus (examples of which are described above), then re-enter the diverter assembly via the inlet 946 , from where they pass through the conduit 942 , through the secondary branch 921 , the choke 930 and the outlet 912 .
- FIG. 27 shows an alternative embodiment of the FIG. 26 design, and like parts are denoted by like numbers having a prime.
- the valve 922 is not needed because the secondary branch 921 ′ continues directly to the production choke 930 ′, instead of rejoining the production wing branch 920 ′.
- the diverter assembly 904 ′ is sealed in the production wing branch 920 ′, which prevents fluids from flowing directly along the production wing branch 920 ′, the fluids instead being diverted through the diverter assembly 904 ′.
- FIG. 28 shows a further embodiment, in which a diverter assembly 1004 is located in an extension 1021 of a production wing branch 1020 beneath a choke 1030 .
- the diverter assembly 1004 is the same as the diverter assemblies of FIGS. 26 and 27 ; it is merely rotated at 90 degrees with respect to the production wing branch 1020 .
- the diverter assembly 1004 is sealed within the branch extension 1021 at a seal 1045 .
- a valve 1022 is located in the branch extension 1021 below the diverter assembly 1004 .
- the branch extension 1021 comprises a primary passage 1060 and a secondary passage 1061 , which departs from the primary passage 1060 on one side of the valve 1022 and rejoins the primary passage 1060 on the other side of the valve 1022 .
- Production fluids pass through the choke 1030 and are diverted by the valve 1022 and the seal 1045 into the axial annular passage 1047 of the diverter assembly 1004 to an outlet 1044 . They are then typically processed by a processing apparatus, as described above, and then they are returned to the bore 1049 of the diverter assembly 1004 , from where they pass through the secondary passage 1061 , back into the primary passage 1060 and out of the outlet 1012 .
- FIG. 29 shows a modified version of the FIG. 28 apparatus, in which like parts are designated by the same reference number with a prime.
- the secondary passage 1061 ′ does not rejoin the primary passage 1060 ′; instead the secondary passage 1061 ′ leads directly to the outlet 1012 ′.
- This embodiment works in the same way as the FIG. 6 embodiment.
- FIGS. 28 and 29 could be modified for use with a conventional Christmas tree by incorporating the diverter assembly 1004 , 1004 ′ into further pipework attached to the tree, instead of within an extension branch of the tree.
- FIG. 30 illustrates an alternative method of using the flow diverter assemblies in the recovery of fluids from multiple wells.
- the flow diverter assemblies can be any of the ones shown in the previously illustrated embodiments, and are not shown in detail in this Figure; for this example, the flow diverter assemblies are the production flow diverter assemblies of FIG. 23 .
- a first diverter assembly 704 is connected to a branch of a first production well A.
- the diverter assembly 704 comprises a conduit (not shown) sealed within the bore of a choke body to provide a first flow region inside the bore of the conduit and a second flow region in the annulus between the conduit and the bore of the choke body. It is emphasised that the diverter assembly 704 is the same as the diverter assembly 604 of FIG. 23 ; however it is being used in a different way, so some outlets of FIG. 23 correspond to inlets of FIG. 30 and vice versa.
- the bore of the conduit has an inlet 712 and an outlet 746 (inlet 712 corresponds to outlet 612 of FIG. 23 and outlet 746 corresponds to inlet 646 of FIG. 23 ).
- the inlet 712 is in communication with an inlet header 701 .
- the inlet header 701 may contain produced fluids from several other production wells (not shown).
- the annular passage between the conduit and the choke body is in communication with the production wing branch of the tree of the first well A, and with the outlet 744 (which corresponds to the outlet 644 in FIG. 23 ).
- a second diverter assembly 714 is connected to a branch of a second production well B.
- the second diverter assembly 714 is the same as the first diverter assembly 704 , and is located in a production wing branch in the same way.
- the bore of the conduit of the second diverter assembly has an inlet 756 (corresponding to the inlet 646 in FIG. 23 ) and an outlet 722 (corresponding to the outlet 612 of FIG. 23 ).
- the outlet 722 is connected to an output header 703 .
- the output header 703 is a conduit for conveying the produced fluids to the surface, for example, and may also be fed from several other wells (not shown).
- the annular passage between the conduit and the inside of the choke body connects the production wing branch to an outlet 754 (which corresponds to the outlet 644 of FIG. 23 ).
- the outlets 746 , 744 and 754 are all connected via tubing to the inlet of a pump 750 .
- Pump 750 then passes all of these fluids into the inlet 756 of the second diverter assembly 714 .
- further fluids from other wells are also pumped by pump 750 and passed into the inlet 756 .
- the second diverter assembly 714 functions in the same way as the diverter assembly 604 of the FIG. 23 embodiment. Fluids from the production bore of the second well B are diverted by the conduit of the second diverter assembly 714 into the annular passage between the conduit and the inside of the choke body, from where they exit through outlet 754 , pass through the pump 750 and are then returned to the bore of the conduit through the inlet 756 . The returned fluids pass straight through the bore of the conduit and into the outlet header 703 , from where they are recovered.
- the first diverter assembly 704 functions differently because the produced fluids from the first well 702 are not returned to the first diverter assembly 704 once they leave the outlet 744 of the annulus. Instead, both of the flow regions inside and outside of the conduit have fluid flowing in the same direction. Inside the conduit (the first flow region), fluids flow upwards from the inlet header 701 straight through the conduit to the outlet 746 . Outside of the conduit (the second flow region), fluids flow upwards from the production bore of the first well 702 to the outlet 744 .
- Both streams of upwardly flowing fluids combine with fluids from the outlet 754 of the second diverter assembly 714 , from where they enter the pump 750 , pass through the second diverter assembly into the outlet header 703 , as described above.
- the tree 601 is a conventional tree but the invention can also be used with horizontal trees.
- One or both of the flow diverter assemblies of the FIG. 23 embodiment could be located within the production bore and/or the annulus bore, instead of within the production and annular choke bodies.
- the processing apparatus 700 could be one or more of a wide variety of equipment.
- the processing apparatus 700 could comprise any of the types of equipment described above with reference to FIG. 17 .
- FIG. 31 shows a further embodiment of a diverter assembly 1110 which is attached to a choke body 1112 , which is located in the production wing branch 1114 of a Christmas tree 1116 .
- the production wing branch 1114 has an outlet 1118 , which is located adjacent to the choke body 1112 .
- the diverter assembly 1110 is attached to the choke body 1112 by a clamp 1119 .
- a first valve V 1 is located in the central bore of the Christmas tree and a second valve V 2 is located in the production wing branch 1114 .
- the choke body 1112 is a standard subsea choke body from which the original choke has been removed.
- the choke body 1112 has a bore which is in fluid communication with the production wing branch 1114 .
- the upper end of the bore of the choke body 1112 terminates in an aperture in the upper surface of the choke body 1112 .
- the lower end of the bore of the choke body communicates with the bore of the production wing branch 1114 and the outlet 1118 .
- the diverter assembly 1110 has a cylindrical housing 1120 , which has an interior axial passage 1122 .
- the lower end of the axial passage 1122 is open; i.e. it terminates in an aperture.
- the upper end of the axial passage 1122 is closed, and a lateral passage 1126 extends from the upper end of the axial passage 1122 to an outlet 1124 in the side wall of the cylindrical housing 1120 .
- the diverter assembly 1110 has a stem 1128 which extends from the upper closed end of the axial passage 1122 , down through the axial passage 1122 , where it terminates in a plug 1130 .
- the stem 1128 is longer than the housing 1120 , so the lower end of the stem 1128 extends beyond the lower end of the housing 1120 .
- the plug 1130 is shaped to engage a seat in the choke body 1112 , so that it blocks the part of the production wing branch 1114 leading to the outlet 1118 . The plug therefore prevents fluids from the production wing branch 1114 or from the choke body 1112 from exiting via the outlet 1118 .
- the plug is optionally provided with a seal, to ensure that no leaking of fluids can take place.
- a choke is typically present inside the choke body 1112 and the outlet 1118 is typically connected to an outlet conduit, which conveys the produced fluids away e.g. to the surface.
- Produced fluids flow through the bore of the Christmas tree 1116 , through valves V 1 and V 2 , through the production wing branch 1114 , and out of outlet 1118 via the choke.
- the diverter assembly 1110 can be retrofitted to a well by closing one or both of the valves V 1 and V 2 of the Christmas tree 1116 . This prevents any fluids leaking into the ocean whilst the diverter assembly 1110 is being fitted.
- the choke (if present) is removed from the choke body 1112 by a standard removal procedure known in the art.
- the diverter assembly 1110 is then clamped onto the top of the choke body 1112 by the clamp 1119 so that the stem 1128 extends into the bore of the choke body 1112 and the plug 1130 engages a seat in the choke body 1112 to block off the outlet 1118 .
- Further pipework (not shown) is then attached to the outlet 1124 of the diverter assembly 1110 . This further pipework can now be used to divert the fluids to any desired location. For example, the fluids may be then diverted to a processing apparatus, or a component of the produced fluids may be diverted into another well bore to be used as injection fluids.
- valves V 1 and V 2 are now re-opened which allows the produced fluids to pass into the production wing branch 1114 and into the choke body 1112 , from where they are diverted from their former route to the outlet 1118 by the plug 1130 , and are instead diverted through the diverter assembly 1110 , out of the outlet 1124 and into the pipework attached to the outlet 1124 .
- FIG. 32 shows an alternative embodiment of a diverter assembly 1110 ′ attached to the Christmas tree 1116 , and like parts will be designated by like numbers having a prime.
- the Christmas tree 1116 is the same Christmas tree 1116 as shown in FIG. 31 , so these reference numbers are not primed.
- the housing 1120 ′ in the diverter assembly 1110 ′ is cylindrical with an axial passage 1122 ′. However, in this embodiment, there is no lateral passage, and the upper end of the axial passage 1122 ′ terminates in an aperture 1130 ′ in the upper end of the housing 1120 ′, so that the upper end of the housing 1120 ′ is open. Thus, the axial passage 1122 ′ extends all of the way through the housing 1120 ′ between its lower and upper ends.
- the aperture 1130 ′ can be connected to external pipework (not shown).
- FIG. 33 shows a further alternative embodiment of a diverter assembly 1110 ′′, and like parts are designated by like numbers having a double prime.
- This Figure is cut off after the valve V 2 ; the rest of the Christmas tree is the same as that of the previous two embodiments. Again, the Christmas tree of this embodiment is the same as those of the previous two embodiments, and so these reference numbers are not primed.
- the housing 1120 ′′ of the FIG. 33 embodiment is substantially the same as the housing 1120 ′ of the FIG. 32 embodiment.
- the housing 1120 ′′ is cylindrical and has an axial passage 1122 ′′ extending therethrough between its lower and upper ends, both of which are open.
- the aperture 1130 ′′ can be connected to external pipework (not shown).
- the housing 1120 ′′ is provided with an extension portion in the form of a conduit 1132 ′′, which extends from near the upper end of the housing 1120 ′′, down through the axial passage 1122 ′′ to a point beyond the end of the housing 1120 ′′.
- the conduit 1132 ′′ is therefore internal to the housing 1120 ′′, and defines an annulus 1134 ′′ between the conduit 1132 ′′ and the housing 1120 ′′.
- the lower end of the conduit 1132 ′′ is adapted to fit inside a recess in the choke body 1112 , and is provided with a seal 1136 , so that it can seal within this recess, and the length of conduit 1132 ′′ is determined accordingly.
- the conduit 1132 ′′ divides the space within the choke body 1112 and the diverter assembly 1110 ′′ into two distinct and separate regions.
- a first region is defined by the bore of the conduit 1132 ′′ and the part of the production wing bore 1114 beneath the choke body 1112 leading to the outlet 1118 .
- the second region is defined by the annulus between the conduit 1132 ′′ and the housing 1120 ′′/the choke body 1112 .
- the conduit 1132 ′′ forms the boundary between these two regions, and the seal 1136 ensures that there is no fluid communication between these two regions, so that they are completely separate.
- the FIG. 33 embodiment is similar to the embodiments of FIGS. 20 and 21 , with the difference that the FIG. 33 annulus is closed at its upper end.
- FIGS. 32 and 33 may function in substantially the same way.
- the valves V 1 and V 2 are closed to allow the choke to be removed from the choke body 1112 and the diverter assembly 1110 ′, 1110 ′′ to be clamped on to the choke body 1112 , as described above with reference to FIG. 31 . Further pipework leading to desired equipment is then attached to the aperture 1130 ′, 1130 ′′.
- the diverter assembly 1110 ′, 1110 ′′ can then be used to divert fluids in either direction therethrough between the apertures 1118 and 1130 ′, 1130 ′′.
- valves V 1 , V 2 are open, and the option to exclude these fluids by closing at least one of these valves.
- FIGS. 32 and 33 can be used to recover fluids from or inject fluids into a well. Any of the embodiments shown attached to a production choke body may alternatively be attached to an annulus choke body of an annulus wing branch leading to an annulus bore of a well.
- FIG. 33 no fluids can pass directly between the production bore and the aperture 1118 via the wing branch 1114 , due to the seal 1136 .
- This embodiment may optionally function as a pipe connector for a flowline not connected to the well.
- the FIG. 33 embodiment could simply be used to connect two pipes together.
- fluids flowing through the axial passage 1132 ′′ may be directed into, or may come from, the well bore via a bypass line.
- FIG. 34 An example of such an embodiment is shown in FIG. 34 .
- FIG. 34 shows the FIG. 33 apparatus attached to the choke body 1112 of the tree 1116 .
- the tree 1116 has a cap 1140 , which has an axial passage 1142 extending therethrough.
- the axial passage 1142 is aligned with and connects directly to the production bore of the tree 1116 .
- a first conduit 1146 connects the axial passage 1142 to a processing apparatus 1148 .
- the processing apparatus 1148 may comprise any of the types of processing apparatus described in this specification.
- a second conduit 1150 connects the processing apparatus 1148 to the aperture 1130 ′′ in the housing 1120 ′′. Valve V 2 is shut and valve V 1 is open.
- the fluids travel up through the production bore of the tree; they cannot pass into through the wing branch 1114 because of the V 2 valve which is closed, and they are instead diverted into the cap 1140 .
- the fluids pass through the conduit 1146 , through the processing apparatus 1148 and they are then conveyed to the axial passage 1122 ′ by the conduit 1150 .
- the fluids travel down the axial passage 1122 ′ to the aperture 1118 and are recovered therefrom via a standard outlet line connected to this aperture.
- the direction of flow is reversed, so that the fluids to be injected are passed into the aperture 1118 and are then conveyed through the axial passage 1122 ′, the conduit 1150 , the processing apparatus 1148 , the conduit 1146 , the cap 1140 and from the cap directly into the production bore of the tree and the well bore.
- This embodiment therefore enables fluids to travel between the well bore and the aperture 1118 of the wing branch 1114 , whilst bypassing the wing branch 1114 itself.
- This embodiment may be especially in wells in which the wing branch valve V 2 has stuck in the closed position.
- the first conduit does not lead to an aperture in the tree cap.
- the first conduit 1146 could instead connect to an annulus branch and an annulus bore; a crossover port could then connect the annulus bore to the production bore, if desired. Any opening into the tree manifold could be used.
- the processing apparatus could comprise any of the types described in this specification, or could alternatively be omitted completely.
- the uses of the invention are very wide ranging.
- the further pipework attached to the diverter assembly could lead to an outlet header, an inlet header, a further well, or some processing apparatus (not shown). Many of these processes may never have been envisaged when the Christmas tree was originally installed, and the invention provides the advantage of being able to adapt these existing trees in a low cost way while reducing the risk of leaks.
- FIG. 35 shows an embodiment of the invention especially adapted for injecting gas into the produced fluids.
- a wellhead cap 40 e is attached to the top of a horizontal tree 400 .
- the wellhead cap 40 e has plugs 408 , 409 ; an inner axial passage 402 ; and an inner lateral passage 404 , connecting the inner axial passage 402 with an inlet 406 .
- One end of a coil tubing insert 410 is attached to the inner axial passage 402 .
- Annular sealing plug 412 is provided to seal the annulus between the top end of coil tubing insert 410 and inner axial passage 402 .
- Coil tubing insert 410 of 2 inch (5 cm) diameter extends downwards from annular sealing plug 412 into the production bore 1 of horizontal Christmas tree 400 .
- inlet 406 is connected to a gas injection line 414 .
- Gas is pumped from gas injection line 414 into Christmas tree cap 40 e , and is diverted by plug 408 down into coil tubing insert 410 ; the gas mixes with the production fluids in the well. The gas reduces the density of the produced fluids, giving them “lift”.
- the mixture of oil well fluids and gas then travels up production bore 1 , in the annulus between production bore 1 and coil tubing insert 410 . This mixture is prevented from travelling into cap 40 e by plug 408 ; instead it is diverted into branch 10 for recovery therefrom.
- This embodiment therefore divides the production bore into two separate regions, so that the production bore can be used both for injecting gases and recovering fluids. This is in contrast to known methods of inject fluids via an annulus bore of the well, which cannot work if the annulus bore becomes blocked. In the conventional methods, which rely on the annulus bore, a blocked annulus bore would mean the entire tree would have to be removed and replaced, whereas the present embodiment provides a quick and inexpensive alternative.
- the diverter assembly is the coil tubing insert 410 and the annular sealing plug 412 .
- FIG. 36 shows a more detailed view of the FIG. 35 apparatus; the apparatus and the function are the same, and like parts are designated by like numbers.
- FIG. 37 shows the gas injection apparatus of FIG. 35 combined with the flow diverter assembly of FIG. 3 and like parts in these two drawings are designated here with like numbers.
- outlet 44 and inlet 46 are also connected to inner axial passage 402 via respective inner lateral passages.
- a booster pump (not shown) is connected between the outlet 44 and the inlet 46 .
- the top end of conduit 42 is sealingly connected at annular seal 416 to inner axial passage 402 above inlet 46 and below outlet 44 .
- Annular sealing plug 412 of coil tubing insert 410 lies between outlet 44 and gas inlet 406 .
- gas is injected through inlet 406 into Christmas tree cap 40 e and is diverted by plug 408 and annular sealing plug 412 into coil tubing insert 410 .
- the gas travels down the coil tubing insert 410 , which extends into the depths of the well.
- the gas combines with the well fluids at the bottom of the wellbore, giving the fluids “lift” and making them easier to pump.
- the booster pump between the outlet 44 and the inlet 46 draws the “gassed” produced fluids up the annulus between the wall of production bore 1 and coil tubing insert 410 .
- the fluids reach conduit 42 , they are diverted by seals 43 into the annulus between conduit 42 and coil tubing insert 410 .
- This embodiment is therefore similar to the FIG. 35 embodiment, additionally allowing for the diversion of fluids to a processing apparatus before returning them to the tree for recovery from the outlet of the branch 10 .
- the conduit 42 is a first diverter assembly
- the coil tubing insert 410 is a second diverter assembly.
- the conduit 42 which forms a secondary diverter assembly in this embodiment, does not have to be located in the production bore.
- Alternative embodiments may use any of the other forms of diverter assembly described in this application (e.g. a diverter assembly on a choke body) in conjunction with the coil tubing insert 410 in the production bore.
- the diverter assembly could be attached to an annulus choke body, instead of to a production choke body.
- FIGS. 20 , 21 , 22 , 24 , 26 to 29 and 32 could also be used in the FIG. 34 method; the FIG. 33 embodiment shown in FIG. 34 is just one possible example.
- FIG. 30 were described with reference to the FIG. 23 embodiment, but these could be accomplished with any of the embodiments providing two separate flowpaths; these include the embodiments of FIGS. 2 to 6 , 17 , 20 to 22 and 26 to 29 .
- the embodiments only providing a single flowpath ( FIGS. 31 and 32 ) could also be used.
- the FIG. 33 embodiment could also be used. Similar considerations apply to well B.
- FIG. 18 which involves recovering fluids from a first well and injecting at least a portion of these fluids into a second well, could likewise be achieved with any of the two-flowpath embodiments of FIGS. 3 to 6 , 17 , 20 to 22 and 26 to 29 .
- the single flowpath embodiments of FIG. 31 and FIG. 32 could be used for the injection well 330 .
- FIG. 38 shows a first recovery well A and a second injection well B.
- Wells A and B each have a tree and a diverter assembly according to FIG. 31 .
- Fluids are recovered from well A via the diverter assembly; the fluids pass into a conduit C and enter a processing apparatus P.
- the processing apparatus includes a separating apparatus and a fluid riser R.
- the processing apparatus separates hydrocarbons from the recovered fluids and sends these into the fluid riser R for recovery to the surface via this riser.
- the remaining fluids are diverted into conduit D which leads to the diverter assembly of the injection well B, and from there, the fluids pass into the well bore.
- This embodiment allows diversion of fluids whilst bypassing the export line which is normally connected to outlets 1118 .
- single flowpath embodiments could also be used for the production well.
- This method can therefore be achieved with a diverter assembly located in the production/annulus bore or in a wing branch, and with most of the embodiments of diverter assembly described in this specification.
- FIG. 23 in which recovery and injection occur in the same well, could be achieved with the flow diverters of FIGS. 2 to 6 (so that at least one of the flow diverters is located in the production bore/annulus bore).
- a first diverter assembly could be located in the production bore and a second diverter assembly could be attached to the annulus choke, for example.
- Further alternative embodiments may have a diverter assembly in the annulus bore, similar to the embodiments of FIGS. 2 to 6 in the production bore.
- FIG. 23 in which recovery and injection occur in the same well, could also be achieved with any of the other diverter assemblies described in the application, including the diverter assemblies which do not provide two separate flowpaths.
- An example of one such modified method is shown in FIG. 39 . This shows the same tree as FIG. 23 , used with two FIG. 31 diverter assemblies.
- this modified method none of the fluids recovered from the first diverter assembly 640 connected to the production bore 602 are returned to the first diverter assembly 640 . Instead, fluids are recovered from the production bore, are diverted through the first diverter assembly 640 into a conduit 690 , which leads to a processing apparatus 700 .
- the processing apparatus 700 could be any of the ones described in this application.
- the processing apparatus 700 including both a separating apparatus and a fluid riser R to the surface.
- the apparatus 700 separates hydrocarbons from the rest of the produced fluids, and the hydrocarbons are recovered to the surface via the fluid riser R, whilst the rest of the fluids are returned to the tree via conduit 696 . These fluids are injected into the annulus bore via the second diverter assembly 680 .
- the methods of recovery and injection are not limited to methods which include the return of some of the recovered fluids to the diverter assembly used in the recovery, or return of the fluids to a second portion of a first flowpath.
- All of the diverter assemblies shown and described can be used for both recovery of fluids and injection of fluids by reversing the flow direction.
- FIGS. 31 to 34 could be connected to other parts of the wing branch, and are not necessarily attached to a choke body.
- these embodiments could be located in series with a choke, at a different point in the wing branch, such as shown in the embodiments of FIGS. 26 to 29 .
Landscapes
- Geology (AREA)
- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Mining & Mineral Resources (AREA)
- Geochemistry & Mineralogy (AREA)
- Fluid Mechanics (AREA)
- Environmental & Geological Engineering (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Physics & Mathematics (AREA)
- Physical Or Chemical Processes And Apparatus (AREA)
- Pipeline Systems (AREA)
- Multiple-Way Valves (AREA)
- Separation Using Semi-Permeable Membranes (AREA)
- Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)
- Quick-Acting Or Multi-Walled Pipe Joints (AREA)
- Jet Pumps And Other Pumps (AREA)
Abstract
Description
- The present invention relates to apparatus and methods for diverting fluids. Embodiments of the invention can be used for recovery and injection Some embodiments relate especially but not exclusively to recovery and injection, into either the same, or a different well.
- Christmas trees are well known in the art of oil and gas wells, and generally comprise an assembly of pipes, valves and fittings installed in a wellhead after completion of drilling and installation of the production tubing to control the flow of oil and gas from the well. Subsea Christmas trees typically have at least two bores one of which communicates with the production tubing (the production bore), and the other of which communicates with the annulus (the annulus bore).
- Typical designs of Christmas tree have a side outlet (a production wing branch) to the production bore closed by a production wing valve for removal of production fluids from the production bore. The annulus bore also typically has an annulus wing branch with a respective annulus wing valve. The top of the production bore and the top of the annulus bore are usually capped by a Christmas tree cap which typically seals off the various bores in the Christmas tree, and provides hydraulic channels for operation of the various valves in the Christmas tree by means of intervention equipment, or remotely from an offshore installation.
- Wells and trees are often active for a long time, and wells from a decade ago may still be in use today. However, technology has progressed a great deal during this time, for example, subsea processing of fluids is now desirable. Such processing can involve adding chemicals, separating water and sand from the hydrocarbons, etc. Furthermore, it is sometimes desired to take fluids from one well and inject a component of these fluids into another well, or into the same well. To do any of these things involves breaking the pipework attached to the outlet of the wing branch, inserting new pipework leading to this processing equipment, alternative well, etc. This provides the problem and large associated risks of disconnecting pipe work which has been in place for a considerable time and which was never intended to be disconnected. Furthermore, due to environmental regulations, no produced fluids are allowed to leak out into the ocean, and any such unanticipated and unconventional disconnection provides the risk that this will occur.
- Conventional methods of extracting fluid from wells involves recovering all of the fluids along pipes to the surface (e.g. a rig or even to land) before the hydrocarbons are separated from the unwanted sand and water. Conveying the sand and water such great distances is wasteful of energy. Furthermore, fluids to be injected into a well are often conveyed over significant distances, which is also a waste of energy.
- In low pressure wells, it is generally desirable to boost the pressure of the production fluids flowing through the production bore, and this is typically done by installing a pump or similar apparatus after the production wing valve in a pipeline or similar leading from the side outlet of the Christmas tree. However, installing such a pump in an active well is a difficult operation, for which production must cease for some time until the pipeline is cut, the pump installed, and the pipeline resealed and tested for integrity.
- A further alternative is to pressure boost the production fluids by installing a pump from a rig, but this requires a well intervention from the rig, which can be even more expensive than breaking the subsea or seabed pipework.
- According to a first aspect of the present invention there is provided a diverter assembly for a manifold of an oil or gas well, comprising a housing having an internal passage, wherein the diverter assembly is adapted to connect to a branch of the manifold.
- According to a second aspect of the invention there is provided a diverter assembly adapted to be inserted within a manifold branch bore, wherein the diverter assembly includes a separator to divide the branch bore into two separate regions.
- The oil or gas well is typically a subsea well but the invention is equally applicable to topside wells.
- The manifold may be a gathering manifold at the junction of several flow lines carrying production fluids from, or conveying injection fluids to, a number of different wells. Alternatively, the manifold may be dedicated to a single well; for example, the manifold may comprise a Christmas tree.
- By “branch” we mean any branch of the manifold, other than a production bore of a tree. The wing branch is typically a lateral branch of the tree, and can be a production or an annulus wing branch connected to a production bore or an annulus bore respectively.
- Optionally, the housing is attached to a choke body. “Choke body” can mean the housing which remains after the manifold's standard choke has been removed. The choke may be a choke of a tree, or a choke of any other kind of manifold.
- The diverter assembly could be located in a branch of the manifold (or a branch extension) in series with a choke. For example, in an embodiment where the manifold comprises a tree, the diverter assembly could be located between the choke and the production wing valve or between the choke and the branch outlet. Further alternative embodiments could have the diverter assembly located in pipework coupled to the manifold, instead of within the manifold itself. Such embodiments allow the diverter assembly to be used in addition to a choke, instead of replacing the choke.
- Embodiments where the diverter assembly is adapted to connect to a branch of a tree means that the tree cap does not have to be removed to fit the diverter assembly. Embodiments of the invention can be easily retro-fitted to existing trees.
- Preferably, the diverter assembly is locatable within a bore in the branch of the manifold.
- Optionally, the internal passage of the diverter assembly is in communication with the interior of the choke body, or other part of the manifold branch.
- The invention provides the advantage that fluids can be diverted from their usual path between the well bore and the outlet of the wing branch. The fluids may be produced fluids being recovered and travelling from the well bore to the outlet of a tree. Alternatively, the fluids may be injection fluids travelling in the reverse direction into the well bore. As the choke is standard equipment, there are well-known and safe techniques of removing and replacing the choke as it wears out. The same tried and tested techniques can be used to remove the choke from the choke body and to clamp the diverter assembly onto the choke body, without the risk of leaking well fluids into the ocean. This enables new pipe work to be connected to the choke body and hence enables safe re-routing of the produced fluids, without having to undertake the considerable risk of disconnecting and reconnecting any of the existing pipes (e.g. the outlet header).
- Some embodiments allow fluid communication between the well bore and the diverter assembly. Other embodiments allow the well bore to be separated from a region of the diverter assembly. The choke body may be a production choke body or an annulus choke body.
- Preferably, a first end of the diverter assembly is provided with a clamp for attachment to a choke body or other part of the manifold branch.
- Optionally, the housing is cylindrical and the internal passage extends axially through the housing between opposite ends of the housing. Alternatively, one end of the internal passage is in a side of the housing.
- Typically, the diverter assembly includes separation means to provide two separate regions within the diverter assembly. Typically, each of these regions has a respective inlet and outlet so that fluid can flow through both of these regions independently.
- Optionally, the housing includes an axial insert portion.
- Typically, the axial insert portion is in the form of a conduit. Typically, the end of the conduit extends beyond the end of the housing. Preferably, the conduit divides the internal passage into a first region comprising the bore of the conduit and a second region comprising the annulus between the housing and the conduit.
- Optionally, the conduit is adapted to seal within the inside of the branch (e.g. inside the choke body) to prevent fluid communication between the annulus and the bore of the conduit.
- Alternatively, the axial insert portion is in the form of a stem. Optionally, the axial insert portion is provided with a plug adapted to block an outlet of the Christmas tree, or other kind of manifold. Preferably, the plug is adapted to fit within and seal inside a passage leading to an outlet of a branch of the manifold.
- Optionally, the diverter assembly provides means for diverting fluids from a first portion of a first flowpath to a second flowpath, and means for diverting the fluids from a second flowpath to a second portion of a first flowpath.
- Preferably, at least a part of the first flowpath comprises a branch of the manifold.
- The first and second portions of the first flowpath could comprise the bore and the annulus of a conduit.
- According to a third aspect of the present invention there is provided a manifold having a branch and a diverter assembly according to the first or second aspects of the invention.
- Optionally, the diverter assembly is attached to the branch so that the internal passage of the diverter assembly is in communication with the interior of the branch.
- Optionally, the manifold has a wing branch outlet, and the internal passage of the diverter assembly is in fluid communication with the wing branch outlet.
- Optionally, a region defined by the diverter assembly is separate from the production bore of the well. Optionally, the internal passage of the diverter assembly is separated from the well bore by a closed valve in the manifold.
- Alternatively, the diverter assembly is provided with an insert in the form of a conduit which defines a first region comprising the bore of the conduit, and a second separate region comprising the annulus between the conduit and the housing. Optionally, one end of the conduit is sealed inside the choke body or other part of the branch, to prevent fluid communication between the first and second regions.
- Optionally, the annulus between the conduit and the housing is closed so that the annulus is in communication with the branch only.
- Alternatively, the annulus has an outlet for connection to further pipes, so that the second region provides a flowpath which is separate from the first region formed by the bore of the conduit.
- Optionally, the first and second regions are connected by pipework. Optionally, a processing apparatus is connected in the pipework so that fluids are processed whilst passing through the connecting pipework.
- Typically, the processing apparatus is chosen from at least one of: a pump; a process fluid turbine; injection apparatus for injecting gas or steam; chemical injection apparatus; a fluid riser; measurement apparatus; temperature measurement apparatus; flow rate measurement apparatus; constitution measurement apparatus; consistency measurement apparatus; gas separation apparatus; water separation apparatus; solids separation apparatus; and hydrocarbon separation apparatus.
- Optionally, the diverter assembly provides a barrier to separate a branch outlet from a branch inlet. The barrier may separate a branch outlet from a production bore of a tree. Optionally, the barrier comprises a plug, which is typically located inside the choke body (or other part of the manifold branch) to block the branch outlet. Optionally, the plug is attached to the housing by a stem which extends axially through the internal passage of the housing.
- Alternatively, the barrier comprises a conduit of the diverter assembly which is engaged within the choke body or other part of the branch.
- Optionally, the manifold is provided with a conduit connecting the first and second regions.
- Optionally, a first set of fluids are recovered from a first well via a first diverter assembly and combined with other fluids in a communal conduit, and the combined fluids are then diverted into an export line via a second diverter assembly connected to a second well.
- According to a fourth aspect of the present invention, there is provided a method of diverting fluids, comprising: connecting a diverter assembly to a branch of a manifold, wherein the diverter assembly comprises a housing having an internal passage; and diverting the fluids through the housing.
- According to a fifth aspect of the present invention there is provided a method of diverting well fluids, the method including the steps of:
-
- diverting fluids from a first portion of a first flowpath to a second flowpath and diverting the fluids from the second flowpath back to a second portion of the first flowpath;
- wherein the fluids are diverted by at least one diverter assembly connected to a branch of a manifold.
- The diverter assembly is optionally located within a choke body; alternatively, the diverter assembly may be coupled in series with a choke. The diverter assembly may be located in the manifold branch adjacent to the choke, or it may be included within a separate extension portion of the manifold branch.
- Typically, the method is for recovering fluids from a well, and includes the final step of diverting fluids to an outlet of the first flowpath for recovery therefrom. Alternatively or additionally, the method is for injecting fluids into a well.
- Optionally, the internal passage of the diverter assembly is in communication with the interior of the branch.
- The fluids may be passed in either direction through the diverter assembly.
- Typically, the diverter assembly includes separation means to provide two separate regions within the diverter assembly, and the method may includes the step of passing fluids through one or both of these regions.
- Optionally, fluids are passed through the first and the second regions in the same direction. Alternatively, fluids are passed through the first and the second regions in opposite directions.
- Optionally, the fluids are passed through one of the first and second regions and subsequently at least a proportion of these fluids are then passed through the other of the first and the second regions. Optionally, the method includes the step of processing the fluids in a processing apparatus before passing the fluids back to the other of the first and second regions.
- Alternatively, fluids may be passed through only one of the two separate regions. For example, the diverter assembly could be used to provide a connection between two flow paths which are unconnected to the well bore, e.g. between two external fluid lines. Optionally, fluids could flow only through a region which is sealed from the branch. For example if the separate regions were provided with a conduit sealed within a manifold branch, fluids may flow through the bore of the conduit only. A flowpath could connect the bore of the conduit to a well bore (production or annulus bore) or another main bore of the tree to bypass the manifold branch. This flowpath could optionally link a region defined by the diverter assembly to a well bore via an aperture in the tree cap.
- Optionally, the first and second regions are connected by pipework. Optionally, a processing apparatus is connected in the pipework so that fluids are processed whilst passing through the connecting pipework.
- The processing apparatus can be, but is not limited to, any of those described above.
- Typically, the method includes the step of removing a choke from the choke body before attaching the diverter assembly to the choke body.
- Optionally, the method includes the step of diverting fluids from a first portion of a first flowpath to a second flowpath and diverting the fluids from the second flowpath to a second portion of the first flowpath.
- For recovering production fluids, the first portion of the first flowpath is typically in communication with the production bore, and the second portion of the first flowpath is typically connected to a pipeline for carrying away the recovered fluids (e.g. to the surface). For injecting fluids into the well, the first portion of the first flowpath is typically connected to an external fluid line, and the second portion of the first flowpath is in communication with the annulus bore. Optionally, the flow directions may be reversed.
- The method provides the advantage that fluids can be diverted (e.g. recovered or injected into the well, or even diverted from another route, bypassing the well completely) without having to remove and replace any pipes already attached to the manifold branch outlet (e.g. a production wing branch outlet).
- Optionally, the method includes the step of recovering fluids from a well and the step of injecting fluids into the well. Optionally, some of the recovered fluids are re-injected into the same well, or a different well.
- For example, the production fluids could be separated into hydrocarbons and water; the hydrocarbons being returned to the first flowpath for recovery therefrom, and the water being returned and injected into the same or a different well.
- Optionally, both of the steps of recovering fluids and injecting fluids include using respective flow diverter assemblies. Alternatively, only one of the steps of recovering and injecting fluids includes using a diverter assembly.
- Optionally, the method includes the step of diverting the fluids through a processing apparatus.
- According to a sixth aspect of the present invention there is provided a manifold having a first diverter assembly according to the first aspect of the invention connected to a first branch and a second diverter assembly according to the first aspect of the invention connected to a second branch.
- Typically, the manifold comprises a tree and the first branch comprises a production wing branch and the second branch comprises an annulus wing branch.
- According to a seventh aspect of the present invention, there is provided a manifold having a first bore having an outlet; a second bore having an outlet; a first diverter assembly connected to the first bore; a second diverter assembly connected to the second bore; and a flowpath connecting the first and second diverter assemblies.
- Typically at least one of the first and second diverter assemblies blocks a passage in the manifold between a bore of the manifold and its respective outlet. Optionally, the manifold comprises a tree, and the first bore comprises a production bore and the second bore comprises an annulus bore.
- Certain embodiments have the advantage that the first and second diverter assemblies can be connected together to allow the unwanted parts of the produced fluids (e.g. water and sand) to be directly injected back into the well, instead of being pumped away with the hydrocarbons. The unwanted materials can be extracted from the hydrocarbons substantially at the wellhead, which reduces the quantity of production fluids to be pumped away, thereby saving energy. The first and second diverter assemblies can alternatively or additionally be used to connect to other kinds of processing apparatus (e.g. the types described with reference to other aspects of the invention), such as a booster pump, filter apparatus, chemical injection apparatus, etc. to allow adding or taking away of substances and adjustment of pressure to be carried out adjacent to the wellhead. The first and second diverter assemblies enable processing to be performed on both fluids being recovered and fluids being injected. Preferred embodiments of the invention enable both recovery and injection to occur simultaneously in the same well.
- Typically, the first and second diverter assemblies are connected to a processing apparatus. The processing apparatus can be any of those described with reference to other aspects of the invention.
- The diverter assembly may be a diverter assembly as described according to any aspect of the invention.
- Typically, a tubing system adapted to both recover and inject fluids is also provided. Preferably, the tubing system is adapted to simultaneously recover and inject fluids.
- According to a eighth aspect of the present invention there is provided a method of recovery of fluids from, and injection of fluids into, a well, wherein the well has a manifold that includes at least one bore and at least one branch having an outlet, the method including the steps of:
-
- blocking a passage in the manifold between a bore of the manifold and its respective branch outlet;
- diverting fluids recovered from the well out of the manifold; and
- injecting fluids into the well;
- wherein neither the fluids being diverted out of the manifold nor the fluids being injected travel through the branch outlet of the blocked passage.
- Preferably, the method is performed using a diverter assembly according to any aspect of the invention.
- Preferably, a processing apparatus is coupled to the second flowpath. The processing apparatus can be any of the ones defined in any aspect of the invention.
- Typically, the processing apparatus separates hydrocarbons from the rest of the produced fluids. Typically, the non-hydrocarbon components of the produced fluids are diverted to the second diverter assembly to provide at least one component of the injection fluids.
- Optionally, at least one component of the injection fluids is provided by an external fluid line which is not connected to the production bore or to the first diverter assembly.
- Optionally, the method includes the step of diverting at least some of the injection fluids from a first portion of a first flowpath to a second flowpath and diverting the fluids from the second flowpath back to a second portion of the first flowpath for injection into the annulus bore of the well.
- Typically, the steps of recovering fluids from the well and injecting fluids into the well are carried out simultaneously.
- According to a ninth aspect of the present invention there is provided a well assembly comprising: a first well having a first diverter assembly; a second well having a second diverter assembly; and a flowpath connecting the first and second diverter assemblies.
- Typically, each of the first and second wells has a tree having a respective bore and a respective outlet, and at least one of the diverter assemblies blocks a passage in the tree between its respective tree bore and its respective tree outlet.
- Typically, an alternative outlet is provided, and the diverter assembly diverts fluids into a path leading to the alternative outlet.
- Optionally, at least one of the first and second diverter assemblies is located within the production bore of its respective tree. Optionally, at least one of the first and second diverter assemblies is connected to a wing branch of its respective tree.
- According to a tenth aspect of the present invention there is provided a method of diverting fluids from a first well to a second well via at least one manifold, the method including the steps of:
-
- blocking a passage in the manifold between a bore of the manifold and a branch outlet of the manifold; and
- diverting at least some of the fluids from the first well to the second well via a path not including the branch outlet of the blocked passage.
- Optionally the at least one manifold comprises a tree of the first well and the method includes the further step of returning a portion of the recovered fluids to the tree of the first well and thereafter recovering that portion of the recovered fluids from the outlet of the blocked passage.
- According to an eleventh aspect of the present invention there is provided a method of recovery of fluids from, and injection of fluids into, a well having a manifold; wherein at least one of the steps of recovery and injection includes diverting fluids from a first portion of a first flowpath to a second flowpath and diverting the fluids from the second flowpath to a second portion of the first flowpath
- Optionally, recovery and injection is simultaneous. Optionally, some of the recovered fluids are re-injected into the well.
- According to a twelfth aspect of the present invention there is provided a method of recovering fluids from a first well and re-injecting at least some of these recovered fluids into a second well, wherein the method includes the steps of diverting fluids from a first portion of a first flowpath to a second flowpath, and diverting at least some of these fluids from the second flowpath to a second portion of the first flowpath.
- Typically, the fluids are recovered from the first well via a first diverter assembly, and wherein the fluids are re-injected into the second well via a second diverter assembly.
- Typically, the method also includes the step of processing the production fluids in a processing apparatus connected between the first and second wells.
- Optionally, the method includes the further step of returning a portion of the recovered fluids to the first diverter assembly and thereafter recovering that portion of the recovered fluids via the first diverter assembly.
- According to a thirteenth aspect of the present invention there is provided a method of recovering fluids from, or injecting fluids into, a well, including the step of diverting the fluids between a well bore and a branch outlet whilst bypassing at least a portion of the branch.
- Such embodiments are useful to divert fluids to a processing apparatus and then to return them to the wing branch outlet for recovery via a standard export line attached to the outlet. The method is also useful if a wing branch valve gets stuck shut.
- Optionally, the fluids are diverted via the tree cap.
- According to a fourteenth aspect of the present invention there is provided a method of injecting fluids into a well, the method comprising diverting fluids from a first portion of a first flowpath to a second flowpath and diverting the fluids from the second flowpath into a second portion of the first flowpath.
- Optionally, the method is performed using a diverter assembly according to any aspect of the invention. The diverter assembly may be locatable in a wide range of places, including, but not limited to: the production bore, the annulus bore, the production wing branch, the annulus wing branch, a production choke body, an annulus choke body, a tree cap or external conduits connected to a tree. The diverter assembly is not necessarily connected to a tree, but may instead be connected to another type of manifold. The first and second flowpaths could comprise some or all of any part of the manifold.
- Typically the first flowpath is a production bore or production line, and the first portion of it is typically a lower part near to the wellhead. Alternatively, the first flowpath comprises an annulus bore. The second portion of the first flowpath is typically a downstream portion of the bore or line adjacent a branch outlet, although the first or second portions can be in the branch or outlet of the first flowpath.
- The diversion of fluids from the first flowpath allows the treatment of the fluids (e.g. with chemicals) or pressure boosting for more efficient recovery before re-entry into the first flowpath.
- Optionally the second flowpath is an annulus bore, or a conduit inserted into the first flowpath. Other types of bore may optionally be used for the second flowpath instead of an annulus bore.
- Typically the flow diversion from the first flowpath to the second flowpath is achieved by a cap on the tree. Optionally, the cap contains a pump or treatment apparatus, but this can be provided separately, or in another part of the apparatus, and in most embodiments of this type, flow will be diverted via the cap to the pump etc and returned to the cap by way of tubing. A connection typically in the form of a conduit is typically provided to transfer fluids between the first and second flowpaths.
- Typically, the diverter assembly can be formed from high grade steels or other metals, using e.g. resilient or inflatable sealing means as required.
- The assembly may include outlets for the first and second flowpaths, for diversion of the fluids to a pump or treatment assembly, or other processing apparatus as described in this application.
- The assembly optionally comprises a conduit capable of insertion into the first flowpath, the assembly having sealing means capable of sealing the conduit against the wall of the production bore. The conduit may provide a flow diverter through its central bore which typically leads to a Christmas tree cap and the pump mentioned previously. The seal effected between the conduit and the first flowpath prevents fluid from the first flowpath entering the annulus between the conduit and the production bore except as described hereinafter. After passing through a typical booster pump, squeeze or scale chemical treatment apparatus, the fluid is diverted into the second flowpath and from there to a crossover back to the first flowpath and first flowpath outlet.
- The assembly and method are typically suited for subsea production wells in normal mode or during well testing, but can also be used in subsea water injection wells, land based oil production injection wells, and geothermal wells.
- The pump can be powered by high pressure water or by electricity which can be supplied direct from a fixed or floating offshore installation, or from a tethered buoy arrangement, or by high pressure gas from a local source.
- The cap preferably seals within Christmas tree bores above the upper master valve. Seals between the cap and bores of the tree are optionally O-ring, inflatable, or preferably metal-to-metal seals. The cap can be retro-fitted very cost effectively with no disruption to existing pipework and minimal impact on control systems already in place.
- The typical design of the flow diverters within the cap can vary with the design of tree, the number, size, and configuration of the diverter channels being matched with the production and annulus bores, and others as the case may be. This provides a way to isolate the pump from the production bore if needed, and also provides a bypass loop.
- The cap is typically capable of retro-fitting to existing trees, and many include equivalent hydraulic fluid conduits for control of tree valves, and which match and co-operate with the conduits or other control elements of the tree to which the cap is being fitted.
- In most preferred embodiments, the cap has outlets for production and annulus flow paths for diversion of fluids away from the cap.
- In accordance with a fifteenth aspect of the invention there is also provided a pump adapted to fit within a bore of a manifold. The manifold optionally comprises a tree, but can be any kind of manifold for an oil or gas well, such as a gathering manifold.
- According to a sixteenth aspect of the present invention there is provided a diverter assembly having a pump according to the fifteenth aspect of the present invention.
- The diverter assembly can be a diverter assembly according to any aspect of the invention, but it is not limited to these.
- The tree is typically a subsea tree, such as a Christmas tree, typically on a subsea well, but a topside tree (or other topside manifold) connected to a topside well could also be appropriate. Horizontal or vertical trees are equally suitable for use of the invention.
- The bore of the tree may be a production bore. However, the diverter assembly and pump could be located in any bore of the tree, for example, in a wing branch bore.
- The flow diverter typically incorporates diverter means to divert fluids flowing through the bore of the tree from a first portion of the bore, through the pump, and back to a second portion of the bore for recovery therefrom via an outlet, which is typically the production wing valve.
- The first portion from which the fluids are initially diverted is typically the production bore/other bore/line of the well, and flow from this portion is typically diverted into a diverter conduit sealed within the bore. Fluid is typically diverted through the bore of the diverter conduit, and after passing therethrough, and exiting the bore of the diverter conduit, typically passes through the annulus created between the diverter conduit and the bore or line. At some point on the diverted fluid path, the fluid passes through the pump internally of the tree, thereby minimising the external profile of the tree, and reducing the chances of damage to the pump.
- The pump is typically powered by a motor, and the type of motor can be chosen from several different forms. In some embodiments of the invention, a hydraulic motor, a turbine motor or moineau motor can be driven by any well-known method, for example an electro-hydraulic power pack or similar power source, and can be connected, either directly or indirectly, to the pump. In certain other embodiments, the motor can be an electric motor, powered by a local power source or by a remote power source.
- Certain embodiments of the present invention allow the construction of wellhead assemblies that can drive the fluid flow in different directions, simply by reversing the flow of the pump, although in some embodiments valves may need to be changed (e.g. reversed) depending on the design of the embodiment.
- The diverter assembly typically includes a tree cap that can be retrofitted to existing designs of tree, and can integrally contain the pump and/or the motor to drive it.
- The flow diverter preferably also comprises a conduit capable of insertion into the bore, and may have sealing means capable of sealing the conduit against the wall of the bore. The flow diverter typically seals within Christmas tree production bores above an upper master valve in a conventional tree, or in the tubing hangar of a horizontal tree, and seals can be optionally O-ring, inflatable, elastomeric or metal to metal seals. The cap or other parts of the flow diverter can comprise hydraulic fluid conduits. The pump can optionally be sealed within the conduit.
- According to a seventeenth aspect of the invention there is provided a method of recovering production fluids from a well having a manifold, the manifold having an integral pump located in a bore of the manifold, and the method comprising diverting fluids from a first portion of a bore of the manifold through the pump and into a second portion of the bore.
- According to an eighteenth aspect of the present invention there is provided a Christmas tree having a diverter assembly sealed in a bore of the tree, wherein the diverter assembly comprises a separator which divides the bore of the tree into two separate regions, and which extends through the tree bore and into the production zone of the well.
- Optionally, the at least one diverter assembly comprises a conduit and at least one seal; the conduit optionally comprises a gas injection line.
- This invention may be used in conjunction with a further diverter assembly according to any other aspect of the invention, or with a diverter assembly in the form of a conduit which is sealed in the production bore. Both diverter assemblies may comprise conduits; one conduit may be arranged concentrically within the other conduit to provide concentric, separate regions within the production bore.
- According to a nineteenth aspect of the present invention there is provided a method of diverting fluids, including the steps of:
-
- providing a fluid diverter assembly sealed in a bore of a tree to form two separate regions in the bore and extending into the production zone of the well;
- injecting fluids into the well via one of the regions; and
- recovering fluids via the other of the regions.
- The injection fluids are typically gases; the method may include the steps of blocking a flowpath between the bore of the tree and a production wing outlet and diverting the recovered fluids out of the tree along an alternative route. The recovered fluids may be diverting the recovered fluids to a processing apparatus and returning at least some of these recovered fluids to the tree and recovering these fluids from a wing branch outlet. The recovered fluids may undergo any of the processes described in this invention, and may be returned to the tree for recovery, or not, (e.g. they may be recovered from a fluid riser) according to any of the described methods and flowpaths.
- Embodiments of the invention will now be described by way of example only and with reference to the accompanying drawings in which:—
-
FIG. 1 is a side sectional view of a typical production tree; -
FIG. 2 is a side view of theFIG. 1 tree with a diverter cap in place; -
FIG. 3 a is a view of theFIG. 1 tree with a second embodiment of a cap in place; -
FIG. 3 b is a view of theFIG. 1 tree with a third embodiment of a cap in place; -
FIG. 4 a is a view of theFIG. 1 tree with a fourth embodiment of a cap in place; and -
FIG. 4 b is a side view of theFIG. 1 tree with a fifth embodiment of a cap in place. -
FIG. 5 shows a side view of a first embodiment of a diverter assembly having an internal pump; -
FIG. 6 shows a similar view of a second embodiment with an internal pump; -
FIG. 7 shows a similar view of a third embodiment with an internal pump; -
FIG. 8 shows a similar view of a fourth embodiment with an internal pump; -
FIG. 9 shows a similar view of a fifth embodiment with an internal pump; -
FIGS. 10 and 11 show a sixth embodiment with an internal pump; -
FIGS. 12 and 13 show a seventh embodiment with an internal pump; -
FIGS. 14 and 15 show an eighth embodiment with an internal pump; -
FIG. 16 shows a ninth embodiment with an internal pump; -
FIG. 17 shows a schematic diagram of theFIG. 2 embodiment coupled to processing apparatus; -
FIG. 18 shows a schematic diagram of two embodiments of the invention engaged with a production well and an injection well respectively, the two wells being connected via a processing apparatus; -
FIG. 19 shows a specific example of theFIG. 18 embodiment; -
FIG. 20 shows a cross-section of an alternative embodiment, which has a diverter conduit located inside a choke body; -
FIG. 21 shows a cross-section of the embodiment ofFIG. 20 located in a horizontal tree; -
FIG. 22 shows a cross-section of a further embodiment, similar to theFIG. 20 embodiment, but also including a choke; -
FIG. 23 shows a cross-sectional view of a tree having a first diverter assembly coupled to a first branch of the tree and a second diverter assembly coupled to a second branch of the tree; -
FIG. 24 shows a schematic view of theFIG. 23 assembly used in conjunction with a first downhole tubing system; -
FIG. 25 shows an alternative embodiment of a downhole tubing system which could be used with theFIG. 23 assembly; -
FIGS. 26 and 27 show alternative embodiments of the invention, each having a diverter assembly coupled to a modified Christmas tree branch between a choke and a production wing valve; -
FIGS. 28 and 29 show further alternative embodiments, each having a diverter assembly coupled to a modified Christmas tree branch below a choke; -
FIG. 30 shows a first diverter assembly used to divert fluids from a first well and connected to an inlet header; and a second diverter assembly used to divert fluids from a second well and connected to an output header; -
FIG. 31 shows a cross-sectional view of an embodiment of a diverter assembly having a central stem; -
FIG. 32 shows a cross-sectional view of an embodiment of a diverter assembly not having a central conduit; -
FIG. 33 shows a cross-sectional view of a further embodiment of a diverter assembly; and -
FIG. 34 shows a cross-sectional view of a possible method of use of theFIG. 33 embodiment to provide a flowpath bypassing a wing branch of the tree; -
FIG. 35 shows a schematic diagram of a tree with a Christmas tree cap having a gas injection line; -
FIG. 36 shows a more detailed view of the apparatus ofFIG. 35 ; -
FIG. 37 shows a combination of the embodiments ofFIGS. 3 and 35 ; -
FIG. 38 shows a further embodiment which is similar toFIG. 23 ; and -
FIG. 39 shows a further embodiment which is similar toFIG. 18 . - Referring now to the drawings, a typical production manifold on an offshore oil or gas wellhead comprises a Christmas tree with a
production bore 1 leading from production tubing (not shown) and carrying production fluids from a perforated region of the production casing in a reservoir (not shown). An annulus bore 2 leads to the annulus between the casing and the production tubing and aChristmas tree cap 4 which seals off the production and annulus bores 1, 2, and provides a number ofhydraulic control channels 3 by which a remote platform or intervention vessel can communicate with and operate the valves in the Christmas tree. Thecap 4 is removable from the Christmas tree in order to expose the production and annulus bores in the event that intervention is required and tools need to be inserted into the production or annulus bores 1, 2. - The flow of fluids through the production and annulus bores is governed by various valves shown in the typical tree of
FIG. 1 . The production bore 1 has abranch 10 which is closed by a production wing valve (PWV) 12. A production swab valve (PSV) 15 closes the production bore 1 above thebranch 10 andPWV 12. Two lower valves UPMV 17 and LPMV 18 (which is optional) close the production bore 1 below thebranch 10 andPWV 12. BetweenUPMV 17 andPSV 15, a crossover port (XOV) 20 is provided in the production bore 1 which connects to a the crossover port (XOV) 21 inannulus bore 2. - The annulus bore is closed by an annulus master valve (AMV) 25 below an
annulus outlet 28 controlled by an annulus wing valve (AWV) 29, itself belowcrossover port 21. Thecrossover port 21 is closed bycrossover valve 30. Anannulus swab valve 32 located above thecrossover port 21 closes the upper end of theannulus bore 2. - All valves in the tree are typically hydraulically controlled (with the exception of LPMV 18 which may be mechanically controlled) by means of
hydraulic control channels 3 passing through thecap 4 and the body of the tool or via hoses as required, in response to signals generated from the surface or from an intervention vessel. - When production fluids are to be recovered from the production bore 1,
LPMV 18 andUPMV 17 are opened,PSV 15 is closed, andPWV 12 is opened to open thebranch 10 which leads to the pipeline (not shown).PSV 15 andASV 32 are only opened if intervention is required. - Referring now to
FIG. 2 , awellhead cap 40 has ahollow conduit 42 with metal, inflatable orresilient seals 43 at its lower end which can seal the outside of theconduit 42 against the inside walls of the production bore 1, diverting production fluids flowing in throughbranch 10 into the annulus between theconduit 42 and the production bore 1 and through theoutlet 46. -
Outlet 46 leads viatubing 216 to processing apparatus 213 (seeFIG. 17 ). Many different types of processing apparatus could be used here. For example, theprocessing apparatus 213 could comprise a pump or process fluid turbine, for boosting the pressure of the fluid. Alternatively, or additionally, the processing apparatus could inject gas, steam, sea water, drill cuttings or waste material into the fluids. The injection of gas could be advantageous, as it would give the fluids “lift”, making them easier to pump. The addition of steam has the effect of adding energy to the fluids. - Injecting sea water into a well could be useful to boost the formation pressure for recovery of hydrocarbons from the well, and to maintain the pressure in the underground formation against collapse. Also, injecting waste gases or drill cuttings etc into a well obviates the need to dispose of these at the surface, which can prove expensive and environmentally damaging.
- The
processing apparatus 213 could also enable chemicals to be added to the fluids, e.g. viscosity moderators, which thin out the fluids, making them easier to pump, or pipe skin friction moderators, which minimise the friction between the fluids and the pipes. Further examples of chemicals which could be injected are surfactants, refrigerants, and well fracturing chemicals.Processing apparatus 213 could also comprise injection water electrolysis equipment. The chemicals/injected materials could be added via one or moreadditional input conduits 214. - Additionally, an
additional input conduit 214 could be used to provide extra fluids to be injected. Anadditional input conduit 214 could, for example, originate from an inlet header (shown inFIG. 30 ). Likewise, anadditional outlet 212 could lead to an outlet header (also shown inFIG. 30 ) for recovery of fluids. - The
processing apparatus 213 could also comprise a fluid riser, which could provide an alternative route between the well bore and the surface. This could be very useful if, for example, thebranch 10 becomes blocked. - Alternatively,
processing apparatus 213 could comprise separation equipment e.g. for separating gas, water, sand/debris and/or hydrocarbons. The separated component(s) could be siphoned off via one or moreadditional process conduits 212. - The
processing apparatus 213 could alternatively or additionally include measurement apparatus, e.g. for measuring the temperature/flow rate/constitution/consistency, etc. The temperature could then be compared to temperature readings taken from the bottom of the well to calculate the temperature change in produced fluids. Furthermore, theprocessing apparatus 213 could include injection water electrolysis equipment. - Alternative embodiments of the invention (described below) can be used for both recovery of production fluids and injection of fluids, and the type of processing apparatus can be selected as appropriate.
- The bore of
conduit 42 can be closed by a cap service valve (CSV) 45 which is normally open but can close off aninlet 44 of the hollow bore of theconduit 42. - After treatment by the
processing apparatus 213 the fluids are returned viatubing 217 to theproduction inlet 44 of thecap 40 which leads to the bore of theconduit 42 and from there the fluids pass into the well bore. The conduit bore and theinlet 46 can also have an optional crossover valve (COV) designated 50, and atree cap adapter 51 in order to adapt the flow diverter channels in thetree cap 40 to a particular design of tree head.Control channels 3 are mated with acap controlling adapter 5 in order to allow continuity of electrical or hydraulic control functions from surface or an intervention vessel. - This embodiment therefore provides a fluid diverter for use with a wellhead tree comprising a thin walled diverter conduit and a seal stack element connected to a modified Christmas tree cap, sealing inside the production bore of the Christmas tree typically above the hydraulic master valve, diverting flow through the conduit annulus, and the top of the Christmas tree cap and tree cap valves to typically a pressure boosting device or chemical treatment apparatus, with the return flow routed via the tree cap to the bore of the diverter conduit and to the well bore.
- Referring to
FIG. 3 a, a further embodiment of acap 40 a has alarge diameter conduit 42 a extending through theopen PSV 15 and terminating in the production bore 1 having seal stack 43 a below thebranch 10, and afurther seal stack 43 b sealing the bore of theconduit 42 a to the inside of the production bore 1 above thebranch 10, leaving an annulus between theconduit 42 a andbore 1.Seals conduit 42 a with reduced diameter in the region of thebranch 10.Seals crossover port 20 communicating viachannel 21 c to thecrossover port 21 of theannulus bore 2. - Injection fluids enter the
branch 10 from where they pass into the annulus between theconduit 42 a and theproduction bore 1. Fluid flow in the axial direction is limited by theseals crossover port 20 into thecrossover channel 21 c. Thecrossover channel 21 c leads to the annulus bore 2 and from there the fluids pass through theoutlet 62 to the pump or chemical treatment apparatus. The treated or pressurised fluids are returned from the pump or treatment apparatus toinlet 61 in theproduction bore 1. The fluids travel down the bore of theconduit 42 a and from there, directly into the well bore. - Cap service valve (CSV) 60 is normally open,
annulus swab valve 32 is normally held open,annulus master valve 25 andannulus wing valve 29 are normally closed, andcrossover valve 30 is normally open. Acrossover valve 65 is provided between the conduit bore 42 a and theannular bore 2 in order to bypass the pump or treatment apparatus if desired. Normally thecrossover valve 65 is maintained closed. - This embodiment maintains a fairly wide bore for more efficient recovery of fluids at relatively high pressure, thereby reducing pressure drops across the apparatus.
- This embodiment therefore provides a fluid diverter for use with a manifold such as a wellhead tree comprising a thin walled diverter with two seal stack elements, connected to a tree cap, which straddles the crossover valve outlet and flowline outlet (which are approximately in the same horizontal plane), diverting flow from the annular space between the straddle and the existing xmas tree bore, through the crossover loop and crossover outlet, into the annulus bore (or annulus flowpath in concentric trees), to the top of the tree cap to pressure boosting or chemical treatment apparatus etc, with the return flow routed via the tree cap and the bore of the conduit.
-
FIG. 3 b shows a simplified version of a similar embodiment, in which theconduit 42 a is replaced by a production bore straddle 70 havingseals seals FIG. 3 a embodiment. In theFIG. 3 b embodiment, production fluids enter via thebranch 10, pass through theopen valve PWV 12 into the annulus between thestraddle 70 and the production bore 1, through thechannel 21 c andcrossover port 20, through theoutlet 62 a to be treated or pressurised etc, and the fluids are then returned via the inlet 61 a, through thestraddle 70, through the open LPMV18 andUPMV 17 to theproduction bore 1. - This embodiment therefore provides a fluid diverter for use with a manifold such as a wellhead tree which is not connected to the tree cap by a thin walled conduit, but is anchored in the tree bore, and which allows full bore flow above the “straddle” portion, but routes flow through the crossover and will allow a swab valve (PSV) to function normally.
- The
FIG. 4 a embodiment has a different design ofcap 40 c with awide bore conduit 42 c extending down the production bore 1 as previously described. Theconduit 42 c substantially fills the production bore 1, and at its distal end seals the production bore at 83 just above thecrossover port 20, and below thebranch 10. ThePSV 15 is, as before, maintained open by theconduit 42 c, andperforations 84 at the lower end of the conduit are provided in the vicinity of thebranch 10.Crossover valve 65 b is provided between the production bore 1 and annulus bore 2 in order to bypass the chemical treatment or pump as required. - The
FIG. 4 a embodiment works in a similar way to the previous embodiments. This embodiment therefore provides a fluid diverter for use with a wellhead tree comprising a thin walled conduit connected to a tree cap, with one seal stack element, which is plugged at the bottom, sealing in the production bore above the hydraulic master valve and crossover outlet (where the crossover outlet is below the horizontal plane of the flowline outlet), diverting flow through the branch to the annular space between the perforated end of the conduit and the existing tree bore, throughperforations 84, through the bore of theconduit 42, to the tree cap, to a treatment or booster apparatus, with the return flow routed through the annulus bore (or annulus flow path in concentric trees) and crossover outlet, to the production bore 1 and the well bore. - Referring now to
FIG. 4 b, a modified embodiment dispenses with theconduit 42 c of theFIG. 4 a embodiment, and simply provides aseal 83 a above theXOV port 20 and below thebranch 10. This embodiment works in the same way as the previous embodiments. - This embodiment provides a fluid diverter for use with a manifold such as a wellhead tree which is not connected to the tree cap by a thin walled conduit, but is anchored in the tree bore and which routes the flow through the crossover and allows full bore flow for the return flow, and will allow the swab valve to function normally.
-
FIG. 5 shows asubsea tree 101 having aproduction bore 123 for the recovery of production fluids from the well. Thetree 101 has acap body 103 that has acentral bore 103 b, and which is attached to thetree 101 so that thebore 103 b of thecap body 103 is aligned with the production bore 123 of the tree. Flow of production fluids through the production bore 123 is controlled by thetree master valve 112, which is normally open, and thetree swab valve 114, which is normally closed during the production phase of the well, so as to divert fluids flowing through the production bore 123 and thetree master valve 112, through theproduction wing valve 113 in the production branch, and to a production line for recovery as is conventional in the art. - In the embodiment of the invention shown in
FIG. 5 , thebore 103 b of thecap body 103 contains a turbine orturbine motor 108 mounted on a shaft that is journalled onbearings 122. The shaft extends continuously through the lower part of the cap body bore 103 b and into the production bore 123 at which point, a turbine pump, centrifugal pump or, as shown here aturbine pump 107 is mounted on the same shaft. Theturbine pump 107 is housed within aconduit 102. - The
turbine motor 108 is configured withinter-collating vanes bore 103 b respectively, so that passage of fluid past the vanes in the direction of thearrows turbine motor 108, and thereby turns the vanes of theturbine pump 107, to which it is directly connected. - The bore of the
conduit 102 housing theturbine pump 107 is open to the production bore 123 at its lower end, but there is a seal between the outer face of theconduit 102 and the inner face of the production bore 123 at that lower end, between thetree master valve 112 and the production wing branch, so that all production fluid passing through the production bore 123 is diverted into the bore of theconduit 102. The seal is typically an elastomeric or a metal to metal seal. - The upper end of the
conduit 102 is sealed in a similar fashion to the inner surface of the cap body bore 103 b, at a lower end thereof, but theconduit 102 hasapertures 102 a allowing fluid communication between the interior of theconduit 102, and theannulus conduit 102 and the bore of the tree. - The
turbine motor 108 is driven by fluid propelled by a hydraulic power pack H which typically flows in the direction ofarrows bore 103 b of the cap turns thevanes 108 v of theturbine motor 108 relative to thevanes 103 v of the bore, thereby turning the shaft and theturbine pump 107. These actions draw fluid from the production bore 123 up through the inside of theconduit 102 and expels the fluid through theapertures 102 a, into theannulus conduit 102 is sealed to the bore above theapertures 102 a, and below the production wing branch at the lower end of theconduit 102, the fluid flowing into theannulus 124 is diverted through theannulus 125 and into the production wing through theproduction wing valve 113 and can be recovered by normal means. - Another benefit of the present embodiment is that the direction of flow of the hydraulic power pack H can be reversed from the configuration shown in
FIG. 5 , and in such case the fluid flow would be in the reverse direction from that shown by the arrows inFIG. 5 , which would allow the re-injection of fluid from theproduction wing valve 113, through theannulus aperture 102 a,conduit 102 and into the production bore 123, all powered by means of thepump 107 andmotor 108 operating in reverse. This can allow water injection or injection of other chemicals or substances into all kinds of wells. - In the
FIG. 5 embodiment, any suitable turbine or moineau motor can be used, and can be powered by any well known method, such as the electro-hydraulic power pack shown inFIG. 5 , but this particular source of power is not essential to the invention. -
FIG. 6 shows a different embodiment that uses anelectric motor 104 instead of theturbine motor 108 to rotate the shaft and theturbine pump 107. Theelectric motor 104 can be powered from an external or a local power source, to which it is connected by cables (not shown) in a conventional manner. Theelectric motor 104 can be substituted for a hydraulic motor or air motor as required. - Like the
FIG. 5 embodiment, the direction of rotation of the shaft can be varied by changing the direction of operation of themotor 104, so as to change the direction of flow of the fluid by the arrows inFIG. 6 to the reverse direction. - Like the
FIG. 5 embodiment, theFIG. 6 assembly can be retrofitted to existing designs of Christmas trees, and can be fitted to many different tree bore diameters. The embodiments described can also be incorporated into new designs of Christmas tree as integral features rather than as retrofit assemblies. Also, the embodiments can be fitted to other kinds of manifold apart from trees, such as gathering manifolds, on subsea or topside wells. -
FIG. 7 shows a further embodiment which illustrates that the connection between the shafts of the motor and the pump can be direct or indirect. In theFIG. 7 embodiment, which is otherwise similar to the previous two embodiments described, theelectrical motor 104 powers adrive belt 109, which in turn powers the shaft of thepump 107. This connection between the shafts of the pump and motor permits a more compact design ofcap 103. Thedrive belt 109 illustrates a direct mechanical type of connection, but could be substituted for a chain drive mechanism, or a hydraulic coupling, or any similar indirect connector such as a hydraulic viscous coupling or well known design. - Like the preceding embodiments, the
FIG. 7 embodiment can be operated in reverse to draw fluids in the opposite direction of the arrows shown, if required to inject fluids such as water, chemicals for treatment, or drill cuttings for disposal into the well. -
FIG. 8 shows a further modified embodiment using ahollow turbine shaft 102 s that draws fluid from the production bore 123 through the inside ofconduit 102 and into the inlet of a combined motor andpump unit pump rotor 107 r is arranged concentrically inside themotor rotor 105 r, both of which are arranged inside amotor stator 105 s. Thepump rotor 107 r and themotor rotor 105 r rotate as a single piece onbearings 122 around the statichollow shaft 102 s thereby drawing fluid from the inside of theshaft 102 through theupper apertures 102 u, and down through theannulus 124 between theshaft 102 s and thebore 103 b of thecap 103. The lower portion of theshaft 102 s is apertured at 1021, and the outer surface of theconduit 102 is sealed within the bore of theshaft 102 s above thelower aperture 1021, so that fluid pumped from theannulus 124 and entering theapertures 1021, continues flowing through theannulus 125 between theconduit 102 and theshaft 102 s into the production bore 123, and finally through theproduction wing valve 113 for export as normal. - The motor can be any prime mover of hollow shaft construction, but electric or hydraulic motors can function adequately in this embodiment. The pump design can be of any suitable type, but a moineau motor, or a turbine as shown here, are both suitable.
- Like previous embodiments, the direction of flow of fluid through the pump shown in
FIG. 8 can be reversed simply by reversing the direction of the motor, so as to drive the fluid in the opposite direction of the arrows shown inFIG. 8 . - Referring now to
FIG. 9 a, this embodiment employs amotor 106 in the form of a disc rotor that is preferably electrically powered, but could be hydraulic or could derive power from any other suitable source, connected to a centrifugal disc-shapedpump 107 that draws fluid from the production bore 123 through the inner bore of theconduit 102 and uses centrifugal impellers to expel the fluid radially outwards into collectingconduits 124, and thence into anannulus 125 formed between theconduit 102 and the production bore 123 in which it is sealed. As previously described in earlier embodiments, the fluid propelled down theannulus 125 cannot pass the seal at the lower end of theconduit 102 below the production wing branch, and exits through theproduction wing valve 113. -
FIG. 9 b shows the same pump configured to operate in reverse, to draw fluids through theproduction wing valve 113, into theconduit 125, across thepump 107, through there-routed conduit 124′ andconduit 102, and into the production bore 123. - One advantage of the
FIG. 9 design is that the disc shaped motor and pump illustrated therein can be duplicated to provide a multi-stage pump with several pump units connected in series and/or in parallel in order to increase the pressure at which the fluid is pumped through theproduction wing valve 113. - Referring now to
FIGS. 10 and 11 , this embodiment illustrates apiston 115 that is sealed within thebore 103 b of thecap 103, and connected via a rod to a furtherlower piston assembly 116 within the bore of theconduit 102. Theconduit 102 is again sealed within thebore 103 b and the production bore 123. The lower end of thepiston assembly 116 has acheck valve 119. - The
piston 115 is moved up from the lower position shown inFIG. 10 a by pumping fluid into theaperture 126 a through the wall of thebore 103 b by means of a hydraulic power pack in the direction shown by the arrows inFIG. 10 a. The piston annulus is sealed below theaperture 126 a, and so a build-up of pressure below the piston pushes it upward towards theaperture 126 b, from which fluid is drawn by the hydraulic power pack. As thepiston 115 travels upward, ahydraulic signal 130 is generated that controls thevalve 117, to maintain the direction of the fluid flow shown inFIG. 10 a. When thepiston 115 reaches its uppermost stroke, anothersignal 131 is generated that switches thevalve 117 and reverses direction of fluid from the hydraulic power pack, so that it enters throughupper aperture 126 b, and is exhausted throughlower aperture 126 a, as shown inFIG. 11 a. Any other similar switching system could be used, and fluid lines are not essential to the invention. - As the piston is moving up as shown in
FIG. 10 a, production fluids in the production bore 123 are drawn into thebore 102 b of theconduit 102, thereby filling thebore 102 b of the conduit underneath the piston. When the piston reaches the upper extent of its travel, and begins to move downwards, thecheck valve 119 opens when the pressure moving the piston downwards exceeds the reservoir pressure in the production bore 123, so that theproduction fluids 123 in thebore 102 b of theconduit 102 flow through thecheck valve 119, and into theannulus 124 between theconduit 102 and the piston shaft. Once the piston reaches the lower extent of its stroke, and the pressure between theannulus 124 and the production bore 123 equalises, thecheck valve 119 in thelower piston assembly 116 closes, trapping the fluid in theannulus 124 above thelower piston assembly 116. At that point, thevalve 117 switches, causing thepiston 115 to rise again and pull thelower piston assembly 116 with it. This lifts the column of fluid in theannulus 124 above thelower piston assembly 116, and once sufficient pressure is generated in the fluid in theannulus 124 abovelower piston assembly 116, thecheck valves 120 at the upper end of the annulus open, thereby allowing the well fluid in the annulus to flow through thecheck valves 120 into theannulus 125, and thereby exhausting throughwing valve 113 branch conduit. When the piston reaches its highest point, the upperhydraulic signal 131 is triggered, changing the direction ofvalve 117, and causing thepistons piston 116 moves down once more, thecheck valve 119 opens to allow well fluid to fill the displaced volume above the movinglower piston assembly 116, and the cycle repeats. - The fluid driven by the hydraulic power pack can be driven by other means. Alternatively, linear oscillating motion can be imparted to the
lower piston assembly 116 by other well-known methods i.e. rotating crank and connecting rod, scotch yolk mechanisms etc. - By reversing and/or re-arranging the orientations of the
check valves FIG. 1 d. - The check valves shown are ball valves, but can be substituted for any other known fluid valve. The
FIGS. 10 and 11 embodiment can be retrofitted to existing trees of varying diameters or incorporated into the design of new trees. - Referring now to
FIGS. 12 and 13 , a further embodiment has a similar piston arrangement as the embodiment shown inFIGS. 10 and 11 , but thepiston assembly bore 103 b of thecap 103. As before, drive fluid is pumped by the hydraulic power pack into the chamber below theupper piston 115, causing it to rise as shown inFIG. 12 a, and thesignal line 130 keeps thevalve 117 in the correct position as thepiston 115 is rising. This draws well fluid through theconduit 102 andcheck valve 119 into the chamber formed in the cap bore 103 b. When the piston has reached its full stroke, thesignal line 131 is triggered to switch thevalve 117 to the position shown inFIG. 13 a, so that drive fluid is pumped in the other direction and thepiston 115 is pushed down. This drivespiston 116 down thebore 103 b expelling well fluid through the check valves 120 (valve 119 is closed), intoannulus production wing valve 113. In this embodiment thecheck valve 119 is located in theconduit 102, but could be immediately above it. By reversing the orientation of the check valves as in previous embodiments the flow of the fluid can be reversed. - A further embodiment is shown in
FIGS. 14 and 15 , which works in a similar fashion but has ashort diverter assembly 102 sealed to the production bore and straddling the production wing branch. Thelower piston 116 strokes in the production bore 123 above thediverter assembly 102. As before, the drive fluid raises thepiston 115 in a first phase shown inFIG. 14 , drawing well fluid through thecheck valve 119, through thediverter assembly 102 and into the upper portion of the production bore 123. When thevalve 117 switches to the configuration shown inFIG. 15 , thepistons bore 123 u, through the check valve 120 (valve 119 is closed) and theproduction wing valve 113. -
FIG. 16 shows a further embodiment, which employs a rotating crank 110 with an eccentrically attachedarm 110 a instead of a fluid drive mechanism to move thepiston 116. Thecrank 110 is pulling the piston upward when in the position shown inFIG. 16 a, and pushing it downward when in the position shown in 16 b. This draws fluid into the upper part of the production bore 123 u as previously described. Thestraddle 102 and check valve arrangements as described in the previous embodiment. - It should be noted that the pump does not have to be located in a production bore; the pump could be located in any bore of the tree with an inlet and an outlet. For example, the pump and diverter assembly may be connected to a wing branch of a tree/a choke body as shown in other embodiments of the invention.
- The present invention can also usefully be used in multiple well combinations, as shown in
FIGS. 18 and 19 .FIG. 18 shows a general arrangement, whereby aproduction well 230 and an injection well 330 are connected together viaprocessing apparatus 220. - The injection well 330 can be any of the capped production well embodiments described above. The production well 230 can also be any of the abovedescribed production well embodiments, with outlets and inlets reversed.
- Produced fluids from production well 230 flow up through the bore of
conduit 42, exit viaoutlet 244, and pass throughtubing 232 toprocessing apparatus 220, which may also have one or morefurther input lines 222 and one or more further outlet lines 224. -
Processing apparatus 220 can be selected to perform any of the functions described above with reference toprocessing apparatus 213 in theFIG. 17 embodiment. Additionally,processing apparatus 220 can also separate water/gas/oil/sand/debris from the fluids produced from production well 230 and then inject one or more of these into injection well 330. Separating fluids from one well and re-injecting into another well viasubsea processing apparatus 220 reduces the quantity of tubing, time and energy necessary compared to performing each function individually as described with respect to theFIG. 17 embodiment.Processing apparatus 220 may also include a riser to the surface, for carrying the produced fluids or a separated component of these to the surface. -
Tubing 233 connectsprocessing apparatus 220 back to aninlet 246 of awellhead cap 240 ofproduction well 230. Theprocessing apparatus 220 could also be used to inject gas into the separated hydrocarbons for lift and also for the injection of any desired chemicals such as scale or wax inhibitors. The hydrocarbons are then returned viatubing 233 toinlet 246 and flow from there into the annulus between theconduit 42 and the bore in which it is disposed. As the annulus is sealed at the upper and lower ends, the fluids flow through theexport line 210 for recovery. - The
horizontal line 310 of injection well 330 serves as an injection line (instead of an export line). Fluids to be injected can enterinjection line 310, from where they pass via the annulus between theconduit 42 and the bore to thetree cap outlet 346 andtubing 235 intoprocessing apparatus 220. The processing apparatus may include a pump, chemical injection device, and/or separating devices, etc. Once the injection fluids have been thus processed as required, they can now be combined with any separated water/sand/debris/other waste material fromproduction well 230. The injection fluids are then transported viatubing 234 to aninlet 344 of thecap 340 of injection well 330, from where they pass through theconduit 42 and into the wellbore. - It should be noted that it is not necessary to have any extra injection fluids entering via
injection line 310; all of the injection fluids could originate from production well 230 instead. Furthermore, as in the previous embodiments, if processingapparatus 220 includes a riser, this riser could be used to transport the processed produced fluids to the surface, instead of passing them back down into the Christmas tree of the production bore again for recovery viaexport line 210. -
FIG. 19 shows a specific example of the more general embodiment ofFIG. 18 and like numbers are used to designate like parts. The processing apparatus in this embodiment includes a waterinjection booster pump 260 connected viatubing 235 to an injection well, aproduction booster pump 270 connected viatubing 232 to a production well, and awater separator vessel 250, connected between the two wells viatubing Pumps electricity power umbilicals - In use, produced fluids from production well 230 exit as previously described via conduit 42 (not shown in
FIG. 19 ),outlet 244 andtubing 232; the pressure of the fluids are boosted bybooster pump 270. The produced fluids then pass intoseparator vessel 250, which separates the hydrocarbons from the produced water. The hydrocarbons are returned toproduction well cap 240 viatubing 233; fromcap 240, they are then directed via the annulus surrounding theconduit 42 toexport line 210. The separated water is transferred viatubing 234 to the wellbore of injection well 330 viainlet 344. - The separated water enters injection well through
inlet 344, from where it passes directly into itsconduit 42 and from there, into the production bore and the depths of injection well 330. - Optionally, it may also be desired to inject additional fluids into injection well 330. This can be done by closing a valve in
tubing 234 to prevent any fluids from entering the injection well viatubing 234. Now, these additional fluids can enter injection well 330 via injection line 310 (which was formerly the export line in previous embodiments). The rest of this procedure will follow that described above with reference toFIG. 17 . Fluids enteringinjection line 310 pass up the annulus between conduit 42 (seeFIGS. 2 and 17 ) and the wellbore, are diverted by the seals 43 (seeFIG. 2 ) at the lower end ofconduit 42 to travel up the annulus, and exit viaoutlet 346. The fluids then pass alongtubing 235, are pressure boosted bybooster pump 260 and are returned viaconduit 237 toinlet 344 of the Christmas tree. From here, the fluids pass through the inside ofconduit 42 and directly into the wellbore and the depths of thewell 330. - Typically, fluids are injected into injection well 330 from tubing 234 (i.e. fluids separated from the produced fluids of production well 230) and from injection line 310 (i.e. any additional fluids) in sequence. Alternatively,
tubings inlet 344 and the two separate lines of injected fluids could be injected into well 330 simultaneously. - In the
FIG. 19 embodiment, the processing apparatus could comprise simply thewater separator vessel 250, and not include either of the booster pumps 260, 270. - Although only two connected wells are shown in
FIGS. 18 and 19 , it should be understood that more wells could also be connected to the processing apparatus. - Two further embodiments of the invention are shown in
FIGS. 20 and 21 ; these embodiments are adapted for use in a traditional and horizontal tree respectively. These embodiments have adiverter assembly 502 located partially inside a Christmastree choke body 500. (The internal parts of the choke have been removed, just leaving choke body 500). Chokebody 500 communicates with an interior bore of a perpendicular extension ofbranch 10. -
Diverter assembly 502 comprises ahousing 504, aconduit 542, aninlet 546 and anoutlet 544.Housing 504 is substantially cylindrical and has anaxial passage 508 extending along its entire length and a connecting lateral passage adjacent to its upper end; the lateral passage leads tooutlet 544. The lower end ofhousing 504 is adapted to attach to the upper end ofchoke body 500 atclamp 506.Axial passage 508 has a reduced diameter portion at its upper end;conduit 542 is located insideaxial passage 508 and extends throughaxial passage 508 as a continuation of the reduced diameter portion. The rest ofaxial passage 508 beyond the reduced diameter portion is of a larger diameter thanconduit 542, creating anannulus 520 between the outside surface ofconduit 542 andaxial passage 508.Conduit 542 extends beyondhousing 504 intochoke body 500, and past the junction betweenbranch 10 and its perpendicular extension. At this point, the perpendicular extension ofbranch 10 becomes anoutlet 530 ofbranch 10; this is the same outlet as shown in theFIG. 2 embodiment.Conduit 542 is sealed to the perpendicular extension atseal 532 just below the junction.Outlet 544 andinlet 546 are typically attached to conduits (not shown) which leads to and from processing apparatus, which could be any of the processing apparatus described above with reference to previous embodiments. - The
diverter assembly 502 can be used to recover fluids from or inject fluids into a well. A method of recovering fluids will now be described. - In use, produced fluids come up the production bore 1, enter
branch 10 and from there enterannulus 520 betweenconduit 542 andaxial passage 508. The fluids are prevented from going downwards towardsoutlet 530 byseal 532, so they are forced upwards inannulus 520, exitingannulus 520 viaoutlet 544.Outlet 544 typically leads to a processing apparatus (which could be any of the ones described earlier, e.g. a pumping or injection apparatus). Once the fluids have been processed, they are returned through a further conduit (not shown) toinlet 546. From here, the fluids pass through the inside ofconduit 542 and exit thoughoutlet 530, from where they are recovered via an export line. - To inject fluids into the well, the embodiments of
FIGS. 20 and 21 can be used with the flow directions reversed. - It is very common for manifolds of various types to have a choke; the
FIG. 20 andFIG. 21 tree embodiments have the advantage that the diverter assembly can be integrated easily with the existing choke body with minimal intervention in the well; locating a part of the diverter assembly in the choke body need not even involve removing well cap 40. - A further embodiment is shown in
FIG. 22 . This is very similar to theFIGS. 20 and 21 embodiments, with achoke 540 coupled (e.g. clamped) to the top ofchoke body 500. Like parts are designated with like reference numerals. Choke 540 is a standard subsea choke. -
Outlet 544 is coupled via a conduit (not shown) toprocessing apparatus 550, which is in turn connected to an inlet ofchoke 540. Choke 540 is a standard choke, having an inner passage with an outlet at its lower end and aninlet 541. The lower end ofpassage 540 is aligned withinlet 546 ofaxial passage 508 ofhousing 504; thus the inner passage ofchoke 540 andaxial passage 508 collectively form one combined axial passage. - A method of recovering fluids will now be described. In use, produced fluids from production bore 1
enter branch 10 and from there enterannulus 520 betweenconduit 542 andaxial passage 508. The fluids are prevented from going downwards towardsoutlet 530 byseal 532, so they are forced upwards inannulus 520, exitingannulus 520 viaoutlet 544.Outlet 544 typically leads to a processing apparatus (which could be any of the ones described earlier, e.g. a pumping or injection apparatus). Once the fluids have been processed, they are returned through a further conduit (not shown) to theinlet 541 ofchoke 540. Choke 540 may be opened, or partially opened as desired to control the pressure of the produced fluids. The produced fluids pass through the inner passage of the choke, throughconduit 542 and exit thoughoutlet 530, from where they are recovered via an export line. - The
FIG. 22 embodiment is useful for embodiments which also require a choke in addition to the diverter assembly ofFIGS. 20 and 21 . Again, theFIG. 22 embodiment can be used to inject fluids into a well by reversing the flow paths. -
Conduit 542 does not necessarily form an extension ofaxial passage 508. Alternative embodiments could include a conduit which is a separate component tohousing 504; this conduit could be sealed to the upper end ofaxial passage 508 aboveoutlet 544, in a similar way asconduit 542 is sealed atseal 532. - Embodiments of the invention can be retrofitted to many different existing designs of manifold, by simply matching the positions and shapes of the
hydraulic control channels 3 in the cap, and providing flow diverting channels or connected to the cap which are matched in position (and preferably size) to the production, annulus and other bores in the tree or other manifold. - Referring now to
FIG. 23 , aconventional tree manifold 601 is illustrated having aproduction bore 602 and anannulus bore 603. - The tree has a
production wing 620 and associatedproduction wing valve 610. Theproduction wing 620 terminates in aproduction choke body 630. Theproduction choke body 630 has aninterior bore 607 extending therethrough in a direction perpendicular to theproduction wing 620. Thebore 607 of the production choke body is in communication with theproduction wing 620 so that thechoke body 630 forms an extension portion of theproduction wing 620. The opening at the lower end of thebore 607 comprises anoutlet 612. In prior art trees, a choke is usually installed in theproduction choke body 630, but in thetree 601 of the present invention, the choke itself has been removed. - Similarly, the
tree 601 also has anannulus wing 621, anannulus wing valve 611, anannulus choke body 631 and aninterior bore 609 of theannulus choke body 631 terminating in aninlet 613 at its lower end. There is no choke inside theannulus choke body 631. - Attached to the
production choke body 630 of theproduction wing 620 is afirst diverter assembly 604 in the form of a production insert. Thediverter assembly 604 is very similar to the flow diverter assemblies ofFIGS. 20 to 22 . - The
production insert 604 comprises a substantiallycylindrical housing 640, aconduit 642, aninlet 646 and anoutlet 644. Thehousing 640 has a reduceddiameter portion 641 at an upper end and an increaseddiameter portion 643 at a lower end. - The
conduit 642 has aninner bore 649, and forms an extension of the reduceddiameter portion 641. Theconduit 642 is longer than thehousing 640 so that it extends beyond the end of thehousing 640. - The space between the outer surface of the
conduit 642 and the inner surface of thehousing 640 forms anaxial passage 647, which ends where theconduit 642 extends out from thehousing 640. A connecting lateral passage is provided adjacent to the join of theconduit 642 and thehousing 640; the lateral passage is in communication with theaxial passage 647 of thehousing 640 and terminates in theoutlet 644. - The lower end of the
housing 640 is attached to the upper end of theproduction choke body 630 at aclamp 648. Theconduit 642 is sealingly attached inside theinner bore 607 of thechoke body 630 at anannular seal 645. - Attached to the
annular choke body 631 is asecond diverter assembly 605. Thesecond diverter assembly 605 is of the same form as thefirst diverter assembly 604. The components of thesecond diverter assembly 605 are the same as those of thefirst diverter assembly 604, including ahousing 680 comprising a reduceddiameter portion 681 and anenlarged diameter portion 683; aconduit 682 extending from the reduceddiameter portion 681 and having abore 689; anoutlet 686; aninlet 684; and anaxial passage 687 formed between theenlarged diameter portion 683 of thehousing 680 and theconduit 682. A connecting lateral passage is provided adjacent to the join of theconduit 682 and thehousing 680; the lateral passage is in communication with theaxial passage 687 of thehousing 680 and terminates in theinlet 684. Thehousing 680 is clamped by aclamp 688 on theannulus choke body 631, and theconduit 682 is sealed to the inside of theannulus choke body 631 atseal 685. - A
conduit 690 connects theoutlet 644 of thefirst diverter assembly 604 to aprocessing apparatus 700. In this embodiment, theprocessing apparatus 700 comprises bulk water separation equipment, which is adapted to separate water from hydrocarbons. Afurther conduit 692 connects theinlet 646 of thefirst diverter assembly 604 to theprocessing apparatus 700. Likewise,conduits outlet 686 and theinlet 684 respectively of thesecond diverter assembly 605 to theprocessing apparatus 700. Theprocessing apparatus 700 haspumps 820 fitted into the conduits between the separation vessel and the first and secondflow diverter assemblies - The production bore 602 and the annulus bore 603 extend down into the well from the
tree 601, where they are connected to atubing system 800 a, shown inFIG. 24 . - The
tubing system 800 a is adapted to allow the simultaneous injection of a first fluid into aninjection zone 805 and production of a second fluid from aproduction zone 804. Thetubing system 800 a comprises aninner tubing 810 which is located inside anouter tubing 812. The production bore 602 is the inner bore of theinner tubing 810. Theinner tubing 810 hasperforations 814 in the region of theproduction zone 804. The outer tubing hasperforations 816 in the region of theinjection zone 805. Acylindrical plug 801 is provided in the annulus bore 603 which lies between theouter tubing 812 and theinner tubing 810. Theplug 801 separates the part of the annulus bore 803 in the region of theinjection zone 805 from the rest of the annulus bore 803. - In use, the produced fluids (typically a mixture of hydrocarbons and water) enter the
inner tubing 810 through theperforations 814 and pass into the production bore 602. The produced fluids then pass through theproduction wing 620, theaxial passage 647, theoutlet 644, and theconduit 690 into theprocessing apparatus 700. Theprocessing apparatus 700 separates the hydrocarbons from the water (and optionally other elements such as sand), e.g. using centrifugal separation. Alternatively or additionally, the processing apparatus can comprise any of the types of processing apparatus mentioned in this specification. - The separated hydrocarbons flow into the
conduit 692, from where they return to thefirst diverter assembly 604 via theinlet 646. The hydrocarbons then flow down through theconduit 642 and exit thechoke body 630 atoutlet 612, e.g. for removal to the surface. - The water separated from the hydrocarbons by the
processing apparatus 700 is diverted through theconduit 696, theaxial passage 687, and theannulus wing 611 into the annulus bore 603. When the water reaches theinjection zone 805, it passes through theperforations 816 in theouter tubing 812 into theinjection zone 805. - If desired, extra fluids can be injected into the well in addition to the separated water. These extra fluids flow into the
second diverter assembly 631 via theinlet 613, flow directly through theconduit 682, theconduit 694 and into theprocessing apparatus 700. These extra fluids are then directed back through theconduit 696 and into the annulus bore 603 as explained above for the path of the separated water. -
FIG. 25 shows an alternative form oftubing system 800 b including aninner tubing 820, anouter tubing 822 and anannular seal 821, for use in situations where aproduction zone 824 is located above aninjection zone 825. Theinner tubing 820 hasperforations 836 in the region of theproduction zone 824 and theouter tubing 822 hasperforations 834 in the region of theinjection zone 825. - The
outer tubing 822, which generally extends round the circumference of theinner tubing 820, is split into a plurality of axial tubes in the region of theproduction zone 824. This allows fluids from theproduction zone 824 to pass between the axial tubes and through theperforations 836 in theinner tubing 820 into the production bore 602. From the production bore 602 the fluids pass upwards into the tree as described above. The returned injection fluids in the annulus bore 603 pass through theperforations 834 in theouter tubing 822 into theinjection zone 825. - The
FIG. 23 embodiment does not necessarily include any kind ofprocessing apparatus 700. TheFIG. 23 embodiment may be used to recover fluids and/or inject fluids, either at the same time, or different times. The fluids to be injected do not necessarily have to originate from any recovered fluids; the injected fluids and recovered fluids may instead be two un-related streams of fluids. Therefore, theFIG. 23 embodiment does not have to be used for re-injection of recovered fluids; it can additionally be used in methods of injection. - The
pumps 820 are optional. - The
tubing system -
FIGS. 26 to 29 illustrate alternative embodiments where the diverter assembly is not inserted within a choke body. These embodiments therefore allow a choke to be used in addition to the diverter assembly. -
FIG. 26 shows a manifold in the form of atree 900 having aproduction bore 902, aproduction wing branch 920, aproduction wing valve 910, anoutlet 912 and aproduction choke 930. Theproduction choke 930 is a full choke, fitted as standard in many Christmas trees, in contrast with theproduction choke body 630 of theFIG. 23 embodiment, from which the actual choke has been removed. InFIG. 26 , theproduction choke 930 is shown in a fully open position. - A
diverter assembly 904 in the form of a production insert is located in theproduction wing branch 920 between theproduction wing valve 910 and theproduction choke 930. Thediverter assembly 904 is the same as thediverter assembly 604 of theFIG. 23 embodiment, and like parts are designated here by like numbers, prefixed by “9”. Like theFIG. 23 embodiment, theFIG. 26 housing 940 is attached to theproduction wing branch 920 at aclamp 948. - The lower end of the
conduit 942 is sealed inside theproduction wing branch 920 at aseal 945. Theproduction wing branch 920 includes asecondary branch 921 which connects the part of theproduction wing branch 920 adjacent to thediverter assembly 904 with the part of theproduction wing branch 920 adjacent to theproduction choke 930. Avalve 922 is located in theproduction wing branch 920 between thediverter assembly 904 and theproduction choke 930. - The combination of the
valve 922 and theseal 945 prevents production fluids from flowing directly from the production bore 902 to theoutlet 912. Instead, the production fluids are diverted into the axialannular passage 947 between theconduit 942 and thehousing 940. The fluids then exit theoutlet 944 into a processing apparatus (examples of which are described above), then re-enter the diverter assembly via theinlet 946, from where they pass through theconduit 942, through thesecondary branch 921, thechoke 930 and theoutlet 912. -
FIG. 27 shows an alternative embodiment of theFIG. 26 design, and like parts are denoted by like numbers having a prime. In this embodiment, thevalve 922 is not needed because thesecondary branch 921′ continues directly to theproduction choke 930′, instead of rejoining theproduction wing branch 920′. Again, thediverter assembly 904′ is sealed in theproduction wing branch 920′, which prevents fluids from flowing directly along theproduction wing branch 920′, the fluids instead being diverted through thediverter assembly 904′. -
FIG. 28 shows a further embodiment, in which adiverter assembly 1004 is located in anextension 1021 of aproduction wing branch 1020 beneath achoke 1030. Thediverter assembly 1004 is the same as the diverter assemblies ofFIGS. 26 and 27 ; it is merely rotated at 90 degrees with respect to theproduction wing branch 1020. - The
diverter assembly 1004 is sealed within thebranch extension 1021 at aseal 1045. Avalve 1022 is located in thebranch extension 1021 below thediverter assembly 1004. - The
branch extension 1021 comprises aprimary passage 1060 and asecondary passage 1061, which departs from theprimary passage 1060 on one side of thevalve 1022 and rejoins theprimary passage 1060 on the other side of thevalve 1022. - Production fluids pass through the
choke 1030 and are diverted by thevalve 1022 and theseal 1045 into the axialannular passage 1047 of thediverter assembly 1004 to anoutlet 1044. They are then typically processed by a processing apparatus, as described above, and then they are returned to thebore 1049 of thediverter assembly 1004, from where they pass through thesecondary passage 1061, back into theprimary passage 1060 and out of theoutlet 1012. -
FIG. 29 shows a modified version of theFIG. 28 apparatus, in which like parts are designated by the same reference number with a prime. In this embodiment, thesecondary passage 1061′ does not rejoin theprimary passage 1060′; instead thesecondary passage 1061′ leads directly to theoutlet 1012′. This embodiment works in the same way as theFIG. 6 embodiment. - The embodiments of
FIGS. 28 and 29 could be modified for use with a conventional Christmas tree by incorporating thediverter assembly -
FIG. 30 illustrates an alternative method of using the flow diverter assemblies in the recovery of fluids from multiple wells. The flow diverter assemblies can be any of the ones shown in the previously illustrated embodiments, and are not shown in detail in this Figure; for this example, the flow diverter assemblies are the production flow diverter assemblies ofFIG. 23 . - A
first diverter assembly 704 is connected to a branch of a first production well A. Thediverter assembly 704 comprises a conduit (not shown) sealed within the bore of a choke body to provide a first flow region inside the bore of the conduit and a second flow region in the annulus between the conduit and the bore of the choke body. It is emphasised that thediverter assembly 704 is the same as thediverter assembly 604 ofFIG. 23 ; however it is being used in a different way, so some outlets ofFIG. 23 correspond to inlets ofFIG. 30 and vice versa. - The bore of the conduit has an
inlet 712 and an outlet 746 (inlet 712 corresponds tooutlet 612 ofFIG. 23 andoutlet 746 corresponds toinlet 646 ofFIG. 23 ). Theinlet 712 is in communication with aninlet header 701. Theinlet header 701 may contain produced fluids from several other production wells (not shown). - The annular passage between the conduit and the choke body is in communication with the production wing branch of the tree of the first well A, and with the outlet 744 (which corresponds to the
outlet 644 inFIG. 23 ). - Likewise, a
second diverter assembly 714 is connected to a branch of a second production well B. Thesecond diverter assembly 714 is the same as thefirst diverter assembly 704, and is located in a production wing branch in the same way. The bore of the conduit of the second diverter assembly has an inlet 756 (corresponding to theinlet 646 inFIG. 23 ) and an outlet 722 (corresponding to theoutlet 612 ofFIG. 23 ). Theoutlet 722 is connected to anoutput header 703. Theoutput header 703 is a conduit for conveying the produced fluids to the surface, for example, and may also be fed from several other wells (not shown). - The annular passage between the conduit and the inside of the choke body connects the production wing branch to an outlet 754 (which corresponds to the
outlet 644 ofFIG. 23 ). - The
outlets pump 750. Pump 750 then passes all of these fluids into theinlet 756 of thesecond diverter assembly 714. Optionally, further fluids from other wells (not shown) are also pumped bypump 750 and passed into theinlet 756. - In use, the
second diverter assembly 714 functions in the same way as thediverter assembly 604 of theFIG. 23 embodiment. Fluids from the production bore of the second well B are diverted by the conduit of thesecond diverter assembly 714 into the annular passage between the conduit and the inside of the choke body, from where they exit throughoutlet 754, pass through thepump 750 and are then returned to the bore of the conduit through theinlet 756. The returned fluids pass straight through the bore of the conduit and into theoutlet header 703, from where they are recovered. - The
first diverter assembly 704 functions differently because the produced fluids from the first well 702 are not returned to thefirst diverter assembly 704 once they leave theoutlet 744 of the annulus. Instead, both of the flow regions inside and outside of the conduit have fluid flowing in the same direction. Inside the conduit (the first flow region), fluids flow upwards from theinlet header 701 straight through the conduit to theoutlet 746. Outside of the conduit (the second flow region), fluids flow upwards from the production bore of the first well 702 to theoutlet 744. - Both streams of upwardly flowing fluids combine with fluids from the
outlet 754 of thesecond diverter assembly 714, from where they enter thepump 750, pass through the second diverter assembly into theoutlet header 703, as described above. - It should be noted that the
tree 601 is a conventional tree but the invention can also be used with horizontal trees. - One or both of the flow diverter assemblies of the
FIG. 23 embodiment could be located within the production bore and/or the annulus bore, instead of within the production and annular choke bodies. - The
processing apparatus 700 could be one or more of a wide variety of equipment. For example, theprocessing apparatus 700 could comprise any of the types of equipment described above with reference toFIG. 17 . - The above described flow paths could be completely reversed or redirected for other process requirements.
-
FIG. 31 shows a further embodiment of adiverter assembly 1110 which is attached to achoke body 1112, which is located in theproduction wing branch 1114 of aChristmas tree 1116. Theproduction wing branch 1114 has anoutlet 1118, which is located adjacent to thechoke body 1112. Thediverter assembly 1110 is attached to thechoke body 1112 by aclamp 1119. A first valve V1 is located in the central bore of the Christmas tree and a second valve V2 is located in theproduction wing branch 1114. - The
choke body 1112 is a standard subsea choke body from which the original choke has been removed. Thechoke body 1112 has a bore which is in fluid communication with theproduction wing branch 1114. The upper end of the bore of thechoke body 1112 terminates in an aperture in the upper surface of thechoke body 1112. The lower end of the bore of the choke body communicates with the bore of theproduction wing branch 1114 and theoutlet 1118. - The
diverter assembly 1110 has acylindrical housing 1120, which has an interioraxial passage 1122. The lower end of theaxial passage 1122 is open; i.e. it terminates in an aperture. The upper end of theaxial passage 1122 is closed, and alateral passage 1126 extends from the upper end of theaxial passage 1122 to anoutlet 1124 in the side wall of thecylindrical housing 1120. - The
diverter assembly 1110 has astem 1128 which extends from the upper closed end of theaxial passage 1122, down through theaxial passage 1122, where it terminates in aplug 1130. Thestem 1128 is longer than thehousing 1120, so the lower end of thestem 1128 extends beyond the lower end of thehousing 1120. Theplug 1130 is shaped to engage a seat in thechoke body 1112, so that it blocks the part of theproduction wing branch 1114 leading to theoutlet 1118. The plug therefore prevents fluids from theproduction wing branch 1114 or from thechoke body 1112 from exiting via theoutlet 1118. The plug is optionally provided with a seal, to ensure that no leaking of fluids can take place. - Before fitting the
diverter assembly 1110 to thetree 1116, a choke is typically present inside thechoke body 1112 and theoutlet 1118 is typically connected to an outlet conduit, which conveys the produced fluids away e.g. to the surface. Produced fluids flow through the bore of theChristmas tree 1116, through valves V1 and V2, through theproduction wing branch 1114, and out ofoutlet 1118 via the choke. - The
diverter assembly 1110 can be retrofitted to a well by closing one or both of the valves V1 and V2 of theChristmas tree 1116. This prevents any fluids leaking into the ocean whilst thediverter assembly 1110 is being fitted. The choke (if present) is removed from thechoke body 1112 by a standard removal procedure known in the art. Thediverter assembly 1110 is then clamped onto the top of thechoke body 1112 by theclamp 1119 so that thestem 1128 extends into the bore of thechoke body 1112 and theplug 1130 engages a seat in thechoke body 1112 to block off theoutlet 1118. Further pipework (not shown) is then attached to theoutlet 1124 of thediverter assembly 1110. This further pipework can now be used to divert the fluids to any desired location. For example, the fluids may be then diverted to a processing apparatus, or a component of the produced fluids may be diverted into another well bore to be used as injection fluids. - The valves V1 and V2 are now re-opened which allows the produced fluids to pass into the
production wing branch 1114 and into thechoke body 1112, from where they are diverted from their former route to theoutlet 1118 by theplug 1130, and are instead diverted through thediverter assembly 1110, out of theoutlet 1124 and into the pipework attached to theoutlet 1124. - Although the above has been described with reference to recovering produced fluids from a well, the same apparatus could equally be used to inject fluids into a well, simply by reversing the flow of the fluids. Injected fluids could enter the
diverter assembly 1110 at theaperture 1124, pass through thediverter assembly 1110, the production wing branch 14 and into the well. Although this example has described aproduction wing branch 1114 which is connected to the production bore of a well, thediverter assembly 1110 could equally be attached to an annulus choke body connected to an annulus wing branch and an annulus bore of the well, and used to divert fluids flowing into or out from the annulus bore. An example of a diverter assembly attached to an annulus choke body has already been described with reference toFIG. 23 . -
FIG. 32 shows an alternative embodiment of adiverter assembly 1110′ attached to theChristmas tree 1116, and like parts will be designated by like numbers having a prime. TheChristmas tree 1116 is thesame Christmas tree 1116 as shown inFIG. 31 , so these reference numbers are not primed. - The
housing 1120′ in thediverter assembly 1110′ is cylindrical with anaxial passage 1122′. However, in this embodiment, there is no lateral passage, and the upper end of theaxial passage 1122′ terminates in anaperture 1130′ in the upper end of thehousing 1120′, so that the upper end of thehousing 1120′ is open. Thus, theaxial passage 1122′ extends all of the way through thehousing 1120′ between its lower and upper ends. Theaperture 1130′ can be connected to external pipework (not shown). -
FIG. 33 shows a further alternative embodiment of adiverter assembly 1110″, and like parts are designated by like numbers having a double prime. This Figure is cut off after the valve V2; the rest of the Christmas tree is the same as that of the previous two embodiments. Again, the Christmas tree of this embodiment is the same as those of the previous two embodiments, and so these reference numbers are not primed. - The
housing 1120″ of theFIG. 33 embodiment is substantially the same as thehousing 1120′ of theFIG. 32 embodiment. Thehousing 1120″ is cylindrical and has anaxial passage 1122″ extending therethrough between its lower and upper ends, both of which are open. Theaperture 1130″ can be connected to external pipework (not shown). - The
housing 1120″ is provided with an extension portion in the form of aconduit 1132″, which extends from near the upper end of thehousing 1120″, down through theaxial passage 1122″ to a point beyond the end of thehousing 1120″. Theconduit 1132″ is therefore internal to thehousing 1120″, and defines anannulus 1134″ between theconduit 1132″ and thehousing 1120″. - The lower end of the
conduit 1132″ is adapted to fit inside a recess in thechoke body 1112, and is provided with aseal 1136, so that it can seal within this recess, and the length ofconduit 1132″ is determined accordingly. - As shown in
FIG. 33 , theconduit 1132″ divides the space within thechoke body 1112 and thediverter assembly 1110″ into two distinct and separate regions. A first region is defined by the bore of theconduit 1132″ and the part of theproduction wing bore 1114 beneath thechoke body 1112 leading to theoutlet 1118. The second region is defined by the annulus between theconduit 1132″ and thehousing 1120″/thechoke body 1112. Thus, theconduit 1132″ forms the boundary between these two regions, and theseal 1136 ensures that there is no fluid communication between these two regions, so that they are completely separate. TheFIG. 33 embodiment is similar to the embodiments ofFIGS. 20 and 21 , with the difference that theFIG. 33 annulus is closed at its upper end. - In use, the embodiments of
FIGS. 32 and 33 may function in substantially the same way. The valves V1 and V2 are closed to allow the choke to be removed from thechoke body 1112 and thediverter assembly 1110′, 1110″ to be clamped on to thechoke body 1112, as described above with reference toFIG. 31 . Further pipework leading to desired equipment is then attached to theaperture 1130′, 1130″. Thediverter assembly 1110′, 1110″ can then be used to divert fluids in either direction therethrough between theapertures - In the
FIG. 32 embodiment, there is the option to divert fluids into or from the well, if the valves V1, V2 are open, and the option to exclude these fluids by closing at least one of these valves. - The embodiments of
FIGS. 32 and 33 can be used to recover fluids from or inject fluids into a well. Any of the embodiments shown attached to a production choke body may alternatively be attached to an annulus choke body of an annulus wing branch leading to an annulus bore of a well. - In the
FIG. 33 embodiment, no fluids can pass directly between the production bore and theaperture 1118 via thewing branch 1114, due to theseal 1136. This embodiment may optionally function as a pipe connector for a flowline not connected to the well. For example, theFIG. 33 embodiment could simply be used to connect two pipes together. Alternatively, fluids flowing through theaxial passage 1132″ may be directed into, or may come from, the well bore via a bypass line. An example of such an embodiment is shown inFIG. 34 . -
FIG. 34 shows theFIG. 33 apparatus attached to thechoke body 1112 of thetree 1116. Thetree 1116 has acap 1140, which has anaxial passage 1142 extending therethrough. Theaxial passage 1142 is aligned with and connects directly to the production bore of thetree 1116. Afirst conduit 1146 connects theaxial passage 1142 to aprocessing apparatus 1148. Theprocessing apparatus 1148 may comprise any of the types of processing apparatus described in this specification. Asecond conduit 1150 connects theprocessing apparatus 1148 to theaperture 1130″ in thehousing 1120″. Valve V2 is shut and valve V1 is open. - To recover fluids from a well, the fluids travel up through the production bore of the tree; they cannot pass into through the
wing branch 1114 because of the V2 valve which is closed, and they are instead diverted into thecap 1140. The fluids pass through theconduit 1146, through theprocessing apparatus 1148 and they are then conveyed to theaxial passage 1122′ by theconduit 1150. The fluids travel down theaxial passage 1122′ to theaperture 1118 and are recovered therefrom via a standard outlet line connected to this aperture. - To inject fluids into a well, the direction of flow is reversed, so that the fluids to be injected are passed into the
aperture 1118 and are then conveyed through theaxial passage 1122′, theconduit 1150, theprocessing apparatus 1148, theconduit 1146, thecap 1140 and from the cap directly into the production bore of the tree and the well bore. - This embodiment therefore enables fluids to travel between the well bore and the
aperture 1118 of thewing branch 1114, whilst bypassing thewing branch 1114 itself. This embodiment may be especially in wells in which the wing branch valve V2 has stuck in the closed position. In modifications to this embodiment, the first conduit does not lead to an aperture in the tree cap. For example, thefirst conduit 1146 could instead connect to an annulus branch and an annulus bore; a crossover port could then connect the annulus bore to the production bore, if desired. Any opening into the tree manifold could be used. The processing apparatus could comprise any of the types described in this specification, or could alternatively be omitted completely. - These embodiments have the advantage of providing a safe way to connect pipework to the well, without having to disconnect any of the existing pipework, and without a significant risk of fluids leaking from the well into the ocean.
- The uses of the invention are very wide ranging. The further pipework attached to the diverter assembly could lead to an outlet header, an inlet header, a further well, or some processing apparatus (not shown). Many of these processes may never have been envisaged when the Christmas tree was originally installed, and the invention provides the advantage of being able to adapt these existing trees in a low cost way while reducing the risk of leaks.
-
FIG. 35 shows an embodiment of the invention especially adapted for injecting gas into the produced fluids. Awellhead cap 40 e is attached to the top of ahorizontal tree 400. Thewellhead cap 40 e hasplugs axial passage 402; and an innerlateral passage 404, connecting the inneraxial passage 402 with aninlet 406. One end of acoil tubing insert 410 is attached to the inneraxial passage 402. Annular sealingplug 412 is provided to seal the annulus between the top end ofcoil tubing insert 410 and inneraxial passage 402.Coil tubing insert 410 of 2 inch (5 cm) diameter extends downwards fromannular sealing plug 412 into the production bore 1 ofhorizontal Christmas tree 400. - In use,
inlet 406 is connected to agas injection line 414. Gas is pumped fromgas injection line 414 intoChristmas tree cap 40 e, and is diverted byplug 408 down intocoil tubing insert 410; the gas mixes with the production fluids in the well. The gas reduces the density of the produced fluids, giving them “lift”. The mixture of oil well fluids and gas then travels up production bore 1, in the annulus between production bore 1 andcoil tubing insert 410. This mixture is prevented from travelling intocap 40 e byplug 408; instead it is diverted intobranch 10 for recovery therefrom. - This embodiment therefore divides the production bore into two separate regions, so that the production bore can be used both for injecting gases and recovering fluids. This is in contrast to known methods of inject fluids via an annulus bore of the well, which cannot work if the annulus bore becomes blocked. In the conventional methods, which rely on the annulus bore, a blocked annulus bore would mean the entire tree would have to be removed and replaced, whereas the present embodiment provides a quick and inexpensive alternative.
- In this embodiment, the diverter assembly is the
coil tubing insert 410 and theannular sealing plug 412. -
FIG. 36 shows a more detailed view of theFIG. 35 apparatus; the apparatus and the function are the same, and like parts are designated by like numbers. -
FIG. 37 shows the gas injection apparatus ofFIG. 35 combined with the flow diverter assembly ofFIG. 3 and like parts in these two drawings are designated here with like numbers. In this figure,outlet 44 andinlet 46 are also connected to inneraxial passage 402 via respective inner lateral passages. - A booster pump (not shown) is connected between the
outlet 44 and theinlet 46. The top end ofconduit 42 is sealingly connected atannular seal 416 to inneraxial passage 402 aboveinlet 46 and belowoutlet 44. Annular sealingplug 412 ofcoil tubing insert 410 lies betweenoutlet 44 andgas inlet 406. - In use, as in the
FIG. 35 embodiment, gas is injected throughinlet 406 intoChristmas tree cap 40 e and is diverted byplug 408 andannular sealing plug 412 intocoil tubing insert 410. The gas travels down thecoil tubing insert 410, which extends into the depths of the well. The gas combines with the well fluids at the bottom of the wellbore, giving the fluids “lift” and making them easier to pump. The booster pump between theoutlet 44 and theinlet 46 draws the “gassed” produced fluids up the annulus between the wall of production bore 1 andcoil tubing insert 410. When the fluids reachconduit 42, they are diverted byseals 43 into the annulus betweenconduit 42 andcoil tubing insert 410. The fluids are then diverted byannular sealing plug 412 throughoutlet 44, through the booster pump, and are returned throughinlet 46. At this point, the fluids pass into the annulus created between the production bore/tree cap inner axial passage andconduit 42, in the volume bounded byseals seals valve 12 andbranch 10 for recovery. - This embodiment is therefore similar to the
FIG. 35 embodiment, additionally allowing for the diversion of fluids to a processing apparatus before returning them to the tree for recovery from the outlet of thebranch 10. In this embodiment, theconduit 42 is a first diverter assembly, and thecoil tubing insert 410 is a second diverter assembly. Theconduit 42, which forms a secondary diverter assembly in this embodiment, does not have to be located in the production bore. Alternative embodiments may use any of the other forms of diverter assembly described in this application (e.g. a diverter assembly on a choke body) in conjunction with thecoil tubing insert 410 in the production bore. - Modifications and improvements may be incorporated without departing from the scope of the invention. For example, as stated above, the diverter assembly could be attached to an annulus choke body, instead of to a production choke body.
- It should be noted that the flow diverters of
FIGS. 20 , 21, 22, 24, 26 to 29 and 32 could also be used in theFIG. 34 method; theFIG. 33 embodiment shown inFIG. 34 is just one possible example. - Likewise, the methods shown in
FIG. 30 were described with reference to theFIG. 23 embodiment, but these could be accomplished with any of the embodiments providing two separate flowpaths; these include the embodiments ofFIGS. 2 to 6 , 17, 20 to 22 and 26 to 29. With modifications to the method ofFIG. 30 , so that fluids from the well A are only required to flow to theoutlet header 703, without any addition of fluids from theinlet header 701, the embodiments only providing a single flowpath (FIGS. 31 and 32 ) could also be used. Alternatively, if fluids were only needed to be diverted between theinlet header 701 and theoutlet header 703, without the addition of any fluids from well A, theFIG. 33 embodiment could also be used. Similar considerations apply to well B. - The method of
FIG. 18 , which involves recovering fluids from a first well and injecting at least a portion of these fluids into a second well, could likewise be achieved with any of the two-flowpath embodiments ofFIGS. 3 to 6 , 17, 20 to 22 and 26 to 29. With modifications to this method (e.g. the removal of the conduit 234), the single flowpath embodiments ofFIG. 31 andFIG. 32 could be used for the injection well 330. Such an embodiment is shown inFIG. 38 , which shows a first recovery well A and a second injection well B. Wells A and B each have a tree and a diverter assembly according toFIG. 31 . Fluids are recovered from well A via the diverter assembly; the fluids pass into a conduit C and enter a processing apparatus P. The processing apparatus includes a separating apparatus and a fluid riser R. The processing apparatus separates hydrocarbons from the recovered fluids and sends these into the fluid riser R for recovery to the surface via this riser. The remaining fluids are diverted into conduit D which leads to the diverter assembly of the injection well B, and from there, the fluids pass into the well bore. This embodiment allows diversion of fluids whilst bypassing the export line which is normally connected tooutlets 1118. - Therefore, with this modification, single flowpath embodiments could also be used for the production well. This method can therefore be achieved with a diverter assembly located in the production/annulus bore or in a wing branch, and with most of the embodiments of diverter assembly described in this specification.
- Likewise, the method of
FIG. 23 , in which recovery and injection occur in the same well, could be achieved with the flow diverters ofFIGS. 2 to 6 (so that at least one of the flow diverters is located in the production bore/annulus bore). A first diverter assembly could be located in the production bore and a second diverter assembly could be attached to the annulus choke, for example. Further alternative embodiments (not shown) may have a diverter assembly in the annulus bore, similar to the embodiments ofFIGS. 2 to 6 in the production bore. - The
FIG. 23 method, in which recovery and injection occur in the same well, could also be achieved with any of the other diverter assemblies described in the application, including the diverter assemblies which do not provide two separate flowpaths. An example of one such modified method is shown inFIG. 39 . This shows the same tree asFIG. 23 , used with twoFIG. 31 diverter assemblies. In this modified method, none of the fluids recovered from thefirst diverter assembly 640 connected to the production bore 602 are returned to thefirst diverter assembly 640. Instead, fluids are recovered from the production bore, are diverted through thefirst diverter assembly 640 into aconduit 690, which leads to aprocessing apparatus 700. Theprocessing apparatus 700 could be any of the ones described in this application. In this embodiment, theprocessing apparatus 700 including both a separating apparatus and a fluid riser R to the surface. Theapparatus 700 separates hydrocarbons from the rest of the produced fluids, and the hydrocarbons are recovered to the surface via the fluid riser R, whilst the rest of the fluids are returned to the tree viaconduit 696. These fluids are injected into the annulus bore via thesecond diverter assembly 680. - Therefore, as illustrated by the examples in
FIGS. 38 and 39 , the methods of recovery and injection are not limited to methods which include the return of some of the recovered fluids to the diverter assembly used in the recovery, or return of the fluids to a second portion of a first flowpath. - All of the diverter assemblies shown and described can be used for both recovery of fluids and injection of fluids by reversing the flow direction.
- Any of the embodiments which are shown connected to a production wing branch could instead be connected to an annulus wing branch, or another branch of the tree. The embodiments of
FIGS. 31 to 34 could be connected to other parts of the wing branch, and are not necessarily attached to a choke body. For example, these embodiments could be located in series with a choke, at a different point in the wing branch, such as shown in the embodiments ofFIGS. 26 to 29 .
Claims (24)
Priority Applications (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US12/541,934 US8272435B2 (en) | 2003-05-31 | 2009-08-15 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US13/536,433 US8540018B2 (en) | 2003-05-31 | 2012-06-28 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
Applications Claiming Priority (11)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
GB0312543.2 | 2003-05-31 | ||
GBGB0312543.2A GB0312543D0 (en) | 2003-05-31 | 2003-05-31 | Method and apparatus |
US10/651,703 US7111687B2 (en) | 1999-05-14 | 2003-08-29 | Recovery of production fluids from an oil or gas well |
US54872704P | 2004-02-26 | 2004-02-26 | |
GB0405454.0 | 2004-03-11 | ||
GBGB0405454.0A GB0405454D0 (en) | 2004-03-11 | 2004-03-11 | Apparatus and method for recovering fluids from a well |
GBGB0405471.4A GB0405471D0 (en) | 2004-03-11 | 2004-03-11 | Apparatus and method for recovering fluids from a well |
GB0405471.4 | 2004-03-11 | ||
PCT/GB2004/002329 WO2005047646A1 (en) | 2003-05-31 | 2004-06-01 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US10/558,593 US7992643B2 (en) | 2003-05-31 | 2004-06-01 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US12/541,934 US8272435B2 (en) | 2003-05-31 | 2009-08-15 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
Related Parent Applications (3)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US10/558,593 Division US7992643B2 (en) | 2002-07-16 | 2004-06-01 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US10558593 Division | 2004-06-01 | ||
PCT/GB2004/002329 Division WO2005047646A1 (en) | 2002-07-16 | 2004-06-01 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
Related Child Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US13/536,433 Division US8540018B2 (en) | 2003-05-31 | 2012-06-28 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
Publications (2)
Publication Number | Publication Date |
---|---|
US20090301727A1 true US20090301727A1 (en) | 2009-12-10 |
US8272435B2 US8272435B2 (en) | 2012-09-25 |
Family
ID=35985578
Family Applications (18)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US10/558,593 Active - Reinstated 2025-04-18 US7992643B2 (en) | 2002-07-16 | 2004-06-01 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US12/541,934 Active 2025-04-16 US8272435B2 (en) | 2003-05-31 | 2009-08-15 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US12/541,936 Expired - Fee Related US7992633B2 (en) | 2003-05-31 | 2009-08-15 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US12/541,938 Expired - Fee Related US8066067B2 (en) | 2003-05-31 | 2009-08-15 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US12/541,937 Expired - Lifetime US8281864B2 (en) | 2003-05-31 | 2009-08-15 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US12/768,337 Expired - Fee Related US8122948B2 (en) | 2003-05-31 | 2010-04-27 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US12/768,324 Expired - Lifetime US8220535B2 (en) | 2003-05-31 | 2010-04-27 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US12/768,332 Expired - Fee Related US8091630B2 (en) | 2003-05-31 | 2010-04-27 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US13/116,889 Expired - Fee Related US8167049B2 (en) | 2002-07-16 | 2011-05-26 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US13/164,291 Expired - Lifetime US8469086B2 (en) | 2002-07-16 | 2011-06-20 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US13/205,284 Expired - Lifetime US8622138B2 (en) | 2003-05-31 | 2011-08-08 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US13/405,997 Expired - Lifetime US8573306B2 (en) | 2003-05-31 | 2012-02-27 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US13/415,635 Expired - Fee Related US8746332B2 (en) | 2002-07-16 | 2012-03-08 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US13/536,433 Expired - Lifetime US8540018B2 (en) | 2003-05-31 | 2012-06-28 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US13/687,290 Expired - Lifetime US8733436B2 (en) | 2002-07-16 | 2012-11-28 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US14/266,936 Active 2024-09-17 US10107069B2 (en) | 2002-07-16 | 2014-05-01 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US14/285,114 Expired - Fee Related US9556710B2 (en) | 2002-07-16 | 2014-05-22 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US15/418,368 Expired - Fee Related US10415346B2 (en) | 2002-07-16 | 2017-01-27 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
Family Applications Before (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US10/558,593 Active - Reinstated 2025-04-18 US7992643B2 (en) | 2002-07-16 | 2004-06-01 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
Family Applications After (16)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US12/541,936 Expired - Fee Related US7992633B2 (en) | 2003-05-31 | 2009-08-15 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US12/541,938 Expired - Fee Related US8066067B2 (en) | 2003-05-31 | 2009-08-15 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US12/541,937 Expired - Lifetime US8281864B2 (en) | 2003-05-31 | 2009-08-15 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US12/768,337 Expired - Fee Related US8122948B2 (en) | 2003-05-31 | 2010-04-27 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US12/768,324 Expired - Lifetime US8220535B2 (en) | 2003-05-31 | 2010-04-27 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US12/768,332 Expired - Fee Related US8091630B2 (en) | 2003-05-31 | 2010-04-27 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US13/116,889 Expired - Fee Related US8167049B2 (en) | 2002-07-16 | 2011-05-26 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US13/164,291 Expired - Lifetime US8469086B2 (en) | 2002-07-16 | 2011-06-20 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US13/205,284 Expired - Lifetime US8622138B2 (en) | 2003-05-31 | 2011-08-08 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US13/405,997 Expired - Lifetime US8573306B2 (en) | 2003-05-31 | 2012-02-27 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US13/415,635 Expired - Fee Related US8746332B2 (en) | 2002-07-16 | 2012-03-08 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US13/536,433 Expired - Lifetime US8540018B2 (en) | 2003-05-31 | 2012-06-28 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US13/687,290 Expired - Lifetime US8733436B2 (en) | 2002-07-16 | 2012-11-28 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US14/266,936 Active 2024-09-17 US10107069B2 (en) | 2002-07-16 | 2014-05-01 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US14/285,114 Expired - Fee Related US9556710B2 (en) | 2002-07-16 | 2014-05-22 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US15/418,368 Expired - Fee Related US10415346B2 (en) | 2002-07-16 | 2017-01-27 | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
Country Status (10)
Country | Link |
---|---|
US (18) | US7992643B2 (en) |
EP (14) | EP1990505B1 (en) |
AT (3) | ATE482324T1 (en) |
AU (2) | AU2004289864B2 (en) |
BR (1) | BRPI0410869B1 (en) |
CA (1) | CA2526714C (en) |
DE (3) | DE602004019212D1 (en) |
EA (1) | EA009139B1 (en) |
NO (1) | NO343392B1 (en) |
WO (1) | WO2005047646A1 (en) |
Cited By (7)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20090308152A1 (en) * | 2007-04-19 | 2009-12-17 | Fmc Technologies, Inc. | Christmas tree with internally positioned flowmeter |
US20100206546A1 (en) * | 2003-05-31 | 2010-08-19 | Cameron International Corporation | Apparatus and Method for Recovering Fluids From a Well and/or Injecting Fluids Into a Well |
US8066076B2 (en) | 2004-02-26 | 2011-11-29 | Cameron Systems (Ireland) Limited | Connection system for subsea flow interface equipment |
US8066063B2 (en) | 2006-09-13 | 2011-11-29 | Cameron International Corporation | Capillary injector |
US8104541B2 (en) | 2006-12-18 | 2012-01-31 | Cameron International Corporation | Apparatus and method for processing fluids from a well |
US8297360B2 (en) | 2006-12-18 | 2012-10-30 | Cameron International Corporation | Apparatus and method for processing fluids from a well |
US10989008B2 (en) | 2016-11-24 | 2021-04-27 | Total E&P Danmark A/S | Cap for a hydrocarbon production well and method of use |
Families Citing this family (90)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20050241834A1 (en) * | 2004-05-03 | 2005-11-03 | Mcglothen Jody R | Tubing/casing connection for U-tube wells |
US7686086B2 (en) * | 2005-12-08 | 2010-03-30 | Vetco Gray Inc. | Subsea well separation and reinjection system |
WO2009024545A1 (en) * | 2007-08-17 | 2009-02-26 | Shell Internationale Research Maatschappij B.V. | Method for controlling production and downhole pressures of a well with multiple subsurface zones and/or branches |
NO330025B1 (en) * | 2008-08-07 | 2011-02-07 | Aker Subsea As | Underwater production plant, method for cleaning an underwater well and method for controlling flow in a hydrocarbon production system |
US8127867B1 (en) | 2008-09-30 | 2012-03-06 | Bronco Oilfield Services, Inc. | Method and system for surface filtering of solids from return fluids in well operations |
GB2466514B (en) * | 2008-12-24 | 2012-09-05 | Weatherford France Sas | Wellhead downhole line communication arrangement |
US8672038B2 (en) * | 2010-02-10 | 2014-03-18 | Magnum Subsea Systems Pte Ltd. | Retrievable subsea bridge tree assembly and method |
US9157293B2 (en) * | 2010-05-06 | 2015-10-13 | Cameron International Corporation | Tunable floating seal insert |
US20120006559A1 (en) * | 2010-07-09 | 2012-01-12 | Brite Alan D | Submergible oil well sealing device with valves and method for installing a submergible oil well sealing device and resuming oil production |
NO332487B1 (en) * | 2011-02-02 | 2012-10-01 | Subsea Solutions As | Method and apparatus for extending at least one valve thread or umbilical cord life |
GB201102252D0 (en) | 2011-02-09 | 2011-03-23 | Operations Ltd Des | Well testing and production apparatus and method |
NO332486B1 (en) * | 2011-05-24 | 2012-10-01 | Subsea Solutions As | Method and apparatus for supplying liquid for deposition treatment and well draining to an underwater well |
US9650843B2 (en) * | 2011-05-31 | 2017-05-16 | Schlumberger Technology Corporation | Junction box to secure and electronically connect downhole tools |
US9291036B2 (en) * | 2011-06-06 | 2016-03-22 | Reel Power Licensing Corp. | Method for increasing subsea accumulator volume |
US9670755B1 (en) * | 2011-06-14 | 2017-06-06 | Trendsetter Engineering, Inc. | Pump module systems for preventing or reducing release of hydrocarbons from a subsea formation |
US20120318520A1 (en) * | 2011-06-14 | 2012-12-20 | Trendsetter Engineering, Inc. | Diverter system for a subsea well |
US20130000918A1 (en) * | 2011-06-29 | 2013-01-03 | Vetco Gray Inc. | Flow module placement between a subsea tree and a tubing hanger spool |
US20130025861A1 (en) * | 2011-07-26 | 2013-01-31 | Marathon Oil Canada Corporation | Methods and Systems for In-Situ Extraction of Bitumen |
US8944159B2 (en) | 2011-08-05 | 2015-02-03 | Cameron International Corporation | Horizontal fracturing tree |
US20130037256A1 (en) * | 2011-08-12 | 2013-02-14 | Baker Hughes Incorporated | Rotary Shoe Direct Fluid Flow System |
US20130206405A1 (en) * | 2011-08-12 | 2013-08-15 | Marathon Oil Canada Corporation | Methods and systems for in-situ extraction of bitumen |
CN102359364A (en) * | 2011-09-15 | 2012-02-22 | 淄博昊洲工贸有限公司 | Depressurizing and charging device for oil production well |
US9068450B2 (en) | 2011-09-23 | 2015-06-30 | Cameron International Corporation | Adjustable fracturing system |
US9134291B2 (en) * | 2012-01-26 | 2015-09-15 | Halliburton Energy Services, Inc. | Systems, methods and devices for analyzing drilling fluid |
GB201202581D0 (en) * | 2012-02-15 | 2012-03-28 | Dashstream Ltd | Method and apparatus for oil and gas operations |
WO2013126592A2 (en) | 2012-02-21 | 2013-08-29 | Cameron International Corporation | Well tree hub and interface for retrievable processing modules |
WO2013160686A2 (en) | 2012-04-26 | 2013-10-31 | Ian Donald | Oilfield apparatus and methods of use |
SG11201406895QA (en) | 2012-04-26 | 2014-11-27 | Ian Donald | Oilfield apparatus and methods of use |
US9284810B2 (en) * | 2012-08-16 | 2016-03-15 | Vetco Gray U.K., Limited | Fluid injection system and method |
US9074449B1 (en) * | 2013-03-06 | 2015-07-07 | Trendsetter Engineering, Inc. | Vertical tree production apparatus for use with a tubing head spool |
US9428981B2 (en) * | 2013-03-15 | 2016-08-30 | Stanley Hosie | Subsea test adaptor for calibration of subsea multi-phase flow meter during initial clean-up and test and methods of using same |
GB2514150B (en) * | 2013-05-15 | 2016-05-18 | Aker Subsea Ltd | Subsea connections |
US9273534B2 (en) | 2013-08-02 | 2016-03-01 | Halliburton Energy Services Inc. | Tool with pressure-activated sliding sleeve |
US9828830B2 (en) * | 2013-09-06 | 2017-11-28 | Schlumberger Technology Corporation | Dual-flow valve assembly |
US9890612B2 (en) * | 2013-09-17 | 2018-02-13 | Oil Addper Services S.R.L. | Self-contained portable unit for steam generation and injection by means of injector wellhead hanger of coiled jacketed capillary tubing with closed circuit and procedure for its operations in oil wells |
US9920590B2 (en) * | 2013-10-25 | 2018-03-20 | Vetco Gray, LLC | Tubing hanger annulus access perforated stem design |
US10083459B2 (en) | 2014-02-11 | 2018-09-25 | The Nielsen Company (Us), Llc | Methods and apparatus to generate a media rank |
BR112016024382A2 (en) | 2014-04-24 | 2017-08-15 | Onesubsea Ip Uk Ltd | self-regulating flow control device |
US9309740B2 (en) | 2014-07-18 | 2016-04-12 | Onesubsea Ip Uk Limited | Subsea completion with crossover passage |
NO339900B1 (en) * | 2014-11-10 | 2017-02-13 | Vetco Gray Scandinavia As | Process and system for pressure control of hydrocarbon well fluids |
NO339866B1 (en) | 2014-11-10 | 2017-02-13 | Vetco Gray Scandinavia As | Method and system for regulating well fluid pressure from a hydrocarbon well |
US9765593B2 (en) * | 2014-12-03 | 2017-09-19 | Ge Oil & Gas Uk Limited | Configurable subsea tree master valve block |
MY174927A (en) | 2014-12-15 | 2020-05-22 | Enpro Subsea Ltd | Apparatus, systems and methods for oil and gas operations |
US9644450B2 (en) | 2015-01-26 | 2017-05-09 | Halliburton Energy Services, Inc. | Well flow control assemblies and associated methods |
US9523259B2 (en) * | 2015-03-05 | 2016-12-20 | Ge Oil & Gas Uk Limited | Vertical subsea tree annulus and controls access |
CN104832143B (en) * | 2015-04-10 | 2017-03-22 | 北京中天油石油天然气科技有限公司 | Water injection well umbilical pipe full-horizon injection regulation device |
GB201506266D0 (en) | 2015-04-13 | 2015-05-27 | Enpro Subsea Ltd | Apparatus, systems and methods for oil and gas operations |
CN104912510B (en) * | 2015-04-27 | 2017-11-07 | 大庆宏测技术服务有限公司 | Injection well overflow re-injection spraying-preventing system |
US9695665B2 (en) * | 2015-06-15 | 2017-07-04 | Trendsetter Engineering, Inc. | Subsea chemical injection system |
CN105064945A (en) * | 2015-07-21 | 2015-11-18 | 大庆庆辉机械设备有限公司 | Testing collecting reinjection full-closed blowout preventer |
US10317875B2 (en) * | 2015-09-30 | 2019-06-11 | Bj Services, Llc | Pump integrity detection, monitoring and alarm generation |
US10533395B2 (en) * | 2016-01-26 | 2020-01-14 | Onesubsea Ip Uk Limited | Production assembly with integrated flow meter |
CA2918978A1 (en) * | 2016-01-26 | 2017-07-26 | Extreme Telematics Corp. | Kinetic energy monitoring for a plunger lift system |
WO2017135941A1 (en) | 2016-02-03 | 2017-08-10 | Fmc Technologies Offshore, Llc | Systems for removing blockages in subsea flowlines and equipment |
US9702215B1 (en) | 2016-02-29 | 2017-07-11 | Fmc Technologies, Inc. | Subsea tree and methods of using the same |
GB2551953B (en) * | 2016-04-11 | 2021-10-13 | Equinor Energy As | Tie in of pipeline to subsea structure |
US10184310B2 (en) | 2016-05-31 | 2019-01-22 | Cameron International Corporation | Flow control module |
BR112019001238B1 (en) * | 2016-07-27 | 2023-03-28 | Fmc Technologies, Inc | UNDERWATER CHRISTMAS TREE AND METHOD FOR CONTROLLING FLUID FLOW FROM A HYDROCARBON WELL |
GB2573212B (en) * | 2016-08-19 | 2020-02-19 | Fourphase As | Solid particle separation in oil and/or gas production |
US10890044B2 (en) * | 2016-10-28 | 2021-01-12 | Onesubsea Ip Uk Limited | Tubular wellhead assembly |
NO344597B1 (en) * | 2016-10-31 | 2020-02-03 | Bri Cleanup As | Method and apparatus for processing fluid from a well |
US10267124B2 (en) | 2016-12-13 | 2019-04-23 | Chevron U.S.A. Inc. | Subsea live hydrocarbon fluid retrieval system and method |
GB2559418B (en) | 2017-02-07 | 2022-01-05 | Equinor Energy As | Method and system for CO2 enhanced oil recovery |
US9945202B1 (en) | 2017-03-27 | 2018-04-17 | Onesubsea Ip Uk Limited | Protected annulus flow arrangement for subsea completion system |
US10808483B2 (en) | 2017-03-28 | 2020-10-20 | Ge Oil & Gas Uk Limited | System for hydrocarbon recovery |
CN107313748B (en) * | 2017-05-31 | 2019-06-11 | 中国石油天然气股份有限公司 | Wellhead assembly and method of operating same |
CN107558962A (en) * | 2017-07-21 | 2018-01-09 | 山西晋城无烟煤矿业集团有限责任公司 | Concentric tube type batch-type gaslift drainage technology |
US10415352B2 (en) * | 2017-09-19 | 2019-09-17 | Resource Rental Tools, LLC | In-line mud screen manifold useful in downhole applications |
CN107724996B (en) * | 2017-09-22 | 2020-01-24 | 中国海洋石油集团有限公司 | Stop valve for natural gas well head |
US11719260B2 (en) | 2017-10-27 | 2023-08-08 | Fmc Technologies, Inc. | Multi-fluid management with inside out fluid systems |
RU2704087C2 (en) * | 2017-11-15 | 2019-10-23 | Леонид Александрович Сорокин | Method of well operation and device for implementation thereof |
GB201803680D0 (en) | 2018-03-07 | 2018-04-25 | Enpro Subsea Ltd | Apparatus, systems and methods for oil and gas operations |
CN108877459A (en) * | 2018-06-20 | 2018-11-23 | 中国石油集团渤海钻探工程有限公司 | A kind of oil drilling well-control blowout prevention device group teaching simulating device |
CN111068530B (en) * | 2018-10-22 | 2022-02-22 | 中国石油天然气股份有限公司 | Microbubble generation device and equipment |
CN109441412A (en) * | 2018-10-31 | 2019-03-08 | 四川富利斯达石油科技发展有限公司 | A kind of layering injection well downhole flow regulator |
CN111173480B (en) * | 2018-11-12 | 2021-09-21 | 中国石油化工股份有限公司 | Natural gas hydrate exploitation method |
US11473403B2 (en) * | 2019-11-07 | 2022-10-18 | Fmc Technologies, Inc. | Sliding sleeve valve and systems incorporating such valves |
RU199626U1 (en) * | 2020-06-25 | 2020-09-10 | Публичное акционерное общество «Татнефть» имени В.Д. Шашина | Device for sealing the mouth of a marginal well |
CN114482953A (en) * | 2020-10-26 | 2022-05-13 | 中国石油化工股份有限公司 | Offshore heavy oil layering viscosity reduction cold recovery pipe column and method |
CN112392430B (en) * | 2020-11-13 | 2021-08-06 | 武汉博汇油田工程服务有限公司 | Universal single-channel manifold pry |
RU2760313C1 (en) * | 2020-12-07 | 2021-11-23 | Общество С Ограниченной Ответственностью "Газпром Добыча Надым" | Method for extraction of hydrocarbon raw materials from multi-layer fields |
CN112664169A (en) * | 2020-12-31 | 2021-04-16 | 胡克 | Accurate water injection method and accurate water injection system for oil field low injection well |
CN113027390B (en) * | 2021-04-06 | 2022-06-07 | 中国石油大学(北京) | Hydrate mining method and device |
RU2763576C1 (en) * | 2021-06-01 | 2021-12-30 | Общество с ограниченной ответственностью «Инженерные Технологии» (ООО «Инженерные Технологии») | Wellhead mounting technology |
CN113914836B (en) * | 2021-10-07 | 2024-04-16 | 哈尔滨艾拓普科技有限公司 | Water distribution and yield allocation device driven by hollow torque motor |
US11692143B1 (en) | 2021-12-20 | 2023-07-04 | Saudi Arabian Oil Company | Crude oil demulsification |
US11952876B2 (en) * | 2022-05-16 | 2024-04-09 | Saudi Arabian Oil Company | Wellbore fluid diversion |
US11885210B2 (en) | 2022-05-19 | 2024-01-30 | Saudi Arabian Oil Company | Water separation and injection |
WO2024044401A1 (en) * | 2022-08-26 | 2024-02-29 | Onesubsea Ip Uk Limited | Subsea well test fluid reinjection |
WO2024062290A1 (en) * | 2022-09-20 | 2024-03-28 | Ergo Exergy Technologies Inc. | Quenching and/or sequestering process fluids within underground carbonaceous formations, and associated systems and methods |
Citations (99)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US1758376A (en) * | 1926-01-09 | 1930-05-13 | Nelson E Reynolds | Method and means to pump oil with fluids |
US1944573A (en) * | 1931-10-12 | 1934-01-23 | William A Raymond | Control head |
US1944840A (en) * | 1933-02-24 | 1934-01-23 | Margia Manning | Control head for wells |
US1994840A (en) * | 1930-05-27 | 1935-03-19 | Caterpillar Tractor Co | Chain |
US2132199A (en) * | 1936-10-12 | 1938-10-04 | Gray Tool Co | Well head installation with choke valve |
US2233077A (en) * | 1938-10-10 | 1941-02-25 | Barker | Well controlling apparatus |
US2276883A (en) * | 1937-05-18 | 1942-03-17 | Standard Catalytic Co | Apparatus for preheating liquid carbonaceous material |
US2412765A (en) * | 1941-07-25 | 1946-12-17 | Phillips Petroleum Co | Recovery of hydrocarbons |
US2790500A (en) * | 1954-03-24 | 1957-04-30 | Edward N Jones | Pump for propelling pellets into oil wells for treating the same |
US2893435A (en) * | 1956-02-03 | 1959-07-07 | Mcevoy Co | Choke |
US2962356A (en) * | 1953-09-09 | 1960-11-29 | Monsanto Chemicals | Corrosion inhibition |
US3101118A (en) * | 1959-08-17 | 1963-08-20 | Shell Oil Co | Y-branched wellhead assembly |
US3163224A (en) * | 1962-04-20 | 1964-12-29 | Shell Oil Co | Underwater well drilling apparatus |
US3358753A (en) * | 1965-12-30 | 1967-12-19 | Shell Oil Co | Underwater flowline installation |
US3378066A (en) * | 1965-09-30 | 1968-04-16 | Shell Oil Co | Underwater wellhead connection |
US3593808A (en) * | 1969-01-07 | 1971-07-20 | Arthur J Nelson | Apparatus and method for drilling underwater |
US3595311A (en) * | 1967-01-19 | 1971-07-27 | Inst Francais Du Petrole | Connecting unit for the completion equipment of a producing underwater well |
US3603409A (en) * | 1969-03-27 | 1971-09-07 | Regan Forge & Eng Co | Method and apparatus for balancing subsea internal and external well pressures |
US3608631A (en) * | 1967-11-14 | 1971-09-28 | Otis Eng Co | Apparatus for pumping tools into and out of a well |
US3688840A (en) * | 1971-02-16 | 1972-09-05 | Cameron Iron Works Inc | Method and apparatus for use in drilling a well |
US3705626A (en) * | 1970-11-19 | 1972-12-12 | Mobil Oil Corp | Oil well flow control method |
US3710859A (en) * | 1970-05-27 | 1973-01-16 | Vetco Offshore Ind Inc | Apparatus for remotely connecting and disconnecting pipe lines to and from a submerged wellhead |
US3777812A (en) * | 1971-11-26 | 1973-12-11 | Exxon Production Research Co | Subsea production system |
US3820558A (en) * | 1973-01-11 | 1974-06-28 | Rex Chainbelt Inc | Combination valve |
US3834460A (en) * | 1971-12-27 | 1974-09-10 | Subsea Equipment Ass Ltd | Well-head assembly |
US3953982A (en) * | 1973-12-05 | 1976-05-04 | Subsea Equipment Associates Limited | Method and apparatus for laying and connecting flow lines to submerged structures |
US3957079A (en) * | 1975-01-06 | 1976-05-18 | C. Jim Stewart & Stevenson, Inc. | Valve assembly for a subsea well control system |
US4042033A (en) * | 1976-10-01 | 1977-08-16 | Exxon Production Research Company | Combination subsurface safety valve and chemical injector valve |
US4046191A (en) * | 1975-07-07 | 1977-09-06 | Exxon Production Research Company | Subsea hydraulic choke |
US4046192A (en) * | 1975-06-13 | 1977-09-06 | Seal Petroleum Limited | Method and apparatus for installing a control valve assembly on an underwater well head |
US4095649A (en) * | 1977-01-13 | 1978-06-20 | Societe Nationale Elf Aquitaine (Production) | Reentry system for subsea well apparatus |
US4099583A (en) * | 1977-04-11 | 1978-07-11 | Exxon Production Research Company | Gas lift system for marine drilling riser |
US4120363A (en) * | 1976-11-26 | 1978-10-17 | Arnold E. Ernst | Root crop harvester |
US4190120A (en) * | 1977-11-18 | 1980-02-26 | Regan Offshore International, Inc. | Moveable guide structure for a sub-sea drilling template |
US4210208A (en) * | 1978-12-04 | 1980-07-01 | Sedco, Inc. | Subsea choke and riser pressure equalization system |
US4223728A (en) * | 1978-11-30 | 1980-09-23 | Garrett Energy Research & Engineering Inc. | Method of oil recovery from underground reservoirs |
US4260022A (en) * | 1978-09-22 | 1981-04-07 | Vetco, Inc. | Through the flow-line selector apparatus and method |
US4274664A (en) * | 1977-08-05 | 1981-06-23 | Compagnie Francaise Des Petroles | Pipe joining device for underseas petroleum pipeline |
US4291772A (en) * | 1980-03-25 | 1981-09-29 | Standard Oil Company (Indiana) | Drilling fluid bypass for marine riser |
US4294471A (en) * | 1979-11-30 | 1981-10-13 | Vetco Inc. | Subsea flowline connector |
US4347899A (en) * | 1980-12-19 | 1982-09-07 | Mobil Oil Corporation | Downhold injection of well-treating chemical during production by gas lift |
US4401164A (en) * | 1981-04-24 | 1983-08-30 | Baugh Benton F | In situ method and apparatus for inspecting and repairing subsea wellheads |
US4403658A (en) * | 1980-09-04 | 1983-09-13 | Hughes Tool Company | Multiline riser support and connection system and method for subsea wells |
US4405016A (en) * | 1980-12-18 | 1983-09-20 | Smith International, Inc. | Underwater Christmas tree cap and lockdown apparatus |
US4444275A (en) * | 1981-12-02 | 1984-04-24 | Standard Oil Company | Carousel for vertically moored platform |
US4457489A (en) * | 1981-07-13 | 1984-07-03 | Gilmore Samuel E | Subsea fluid conduit connections for remote controlled valves |
US4478287A (en) * | 1983-01-27 | 1984-10-23 | Hydril Company | Well control method and apparatus |
US4502534A (en) * | 1982-12-13 | 1985-03-05 | Hydril Company | Flow diverter |
US4503878A (en) * | 1983-04-29 | 1985-03-12 | Cameron Iron Works, Inc. | Choke valve |
US4509599A (en) * | 1982-10-01 | 1985-04-09 | Baker Oil Tools, Inc. | Gas well liquid removal system and process |
US4572298A (en) * | 1982-11-05 | 1986-02-25 | Hydril Company | Gate valve apparatus and method |
US4589493A (en) * | 1984-04-02 | 1986-05-20 | Cameron Iron Works, Inc. | Subsea wellhead production apparatus with a retrievable subsea choke |
US4607701A (en) * | 1984-11-01 | 1986-08-26 | Vetco Offshore Industries, Inc. | Tree control manifold |
US4610570A (en) * | 1984-11-27 | 1986-09-09 | Vickers Public Limited Company | Marine anchors |
US4626135A (en) * | 1984-10-22 | 1986-12-02 | Hydril Company | Marine riser well control method and apparatus |
US4646844A (en) * | 1984-12-24 | 1987-03-03 | Hydril Company | Diverter/bop system and method for a bottom supported offshore drilling rig |
US4648629A (en) * | 1985-05-01 | 1987-03-10 | Vetco Offshore, Inc. | Underwater connector |
US4749046A (en) * | 1986-05-28 | 1988-06-07 | Otis Engineering Corporation | Well drilling and completion apparatus |
US4848473A (en) * | 1987-12-21 | 1989-07-18 | Chevron Research Company | Subsea well choke system |
US4874008A (en) * | 1988-04-20 | 1989-10-17 | Cameron Iron Works U.S.A., Inc. | Valve mounting and block manifold |
US5010956A (en) * | 1990-03-28 | 1991-04-30 | Exxon Production Research Company | Subsea tree cap well choke system |
US5143158A (en) * | 1990-04-27 | 1992-09-01 | Dril-Quip, Inc. | Subsea wellhead apparatus |
US5295534A (en) * | 1991-04-15 | 1994-03-22 | Texaco Inc. | Pressure monitoring of a producing well |
US5398761A (en) * | 1993-05-03 | 1995-03-21 | Syntron, Inc. | Subsea blowout preventer modular control pod |
US5492436A (en) * | 1994-04-14 | 1996-02-20 | Pool Company | Apparatus and method for moving rig structures |
US5526882A (en) * | 1995-01-19 | 1996-06-18 | Sonsub, Inc. | Subsea drilling and production template system |
US5535826A (en) * | 1992-06-17 | 1996-07-16 | Petroleum Engineering Services Limited | Well-head structures |
US5544707A (en) * | 1992-06-01 | 1996-08-13 | Cooper Cameron Corporation | Wellhead |
US5868204A (en) * | 1997-05-08 | 1999-02-09 | Abb Vetco Gray Inc. | Tubing hanger vent |
US5971077A (en) * | 1996-11-22 | 1999-10-26 | Abb Vetco Gray Inc. | Insert tree |
US5992526A (en) * | 1997-12-03 | 1999-11-30 | Fmc Corporation | ROV deployed tree cap for a subsea tree and method of installation |
US5992527A (en) * | 1996-11-29 | 1999-11-30 | Cooper Cameron Corporation | Wellhead assembly |
US6050339A (en) * | 1996-12-06 | 2000-04-18 | Abb Vetco Gray Inc. | Annulus porting of horizontal tree |
US6109352A (en) * | 1995-09-23 | 2000-08-29 | Expro North Sea Limited | Simplified Xmas tree using sub-sea test tree |
US6138774A (en) * | 1998-03-02 | 2000-10-31 | Weatherford Holding U.S., Inc. | Method and apparatus for drilling a borehole into a subsea abnormal pore pressure environment |
US6145596A (en) * | 1999-03-16 | 2000-11-14 | Dallas; L. Murray | Method and apparatus for dual string well tree isolation |
US6209650B1 (en) * | 1996-08-27 | 2001-04-03 | Den Norske Stats Oljeselskap As | Subsea well |
US6227300B1 (en) * | 1997-10-07 | 2001-05-08 | Fmc Corporation | Slimbore subsea completion system and method |
US6460621B2 (en) * | 1999-12-10 | 2002-10-08 | Abb Vetco Gray Inc. | Light-intervention subsea tree system |
US6481504B1 (en) * | 1999-06-29 | 2002-11-19 | Fmc Corporation | Flowline connector with subsea equipment package |
US6497286B1 (en) * | 1998-03-27 | 2002-12-24 | Cooper Cameron Corporation | Method and apparatus for drilling a plurality of offshore underwater wells |
US6554075B2 (en) * | 2000-12-15 | 2003-04-29 | Halliburton Energy Services, Inc. | CT drilling rig |
US6557629B2 (en) * | 2000-09-29 | 2003-05-06 | Fmc Technologies, Inc. | Wellhead isolation tool |
US6612369B1 (en) * | 2001-06-29 | 2003-09-02 | Kvaerner Oilfield Products | Umbilical termination assembly and launching system |
US6612368B2 (en) * | 2000-03-24 | 2003-09-02 | Fmc Technologies, Inc. | Flow completion apparatus |
US6637514B1 (en) * | 1999-05-14 | 2003-10-28 | Des Enhanced Recovery Limited | Recovery of production fluids from an oil or gas well |
US6648072B1 (en) * | 1999-07-20 | 2003-11-18 | Smith International, Inc. | Method and apparatus for delivery of treatment chemicals to subterranean wells |
US6675900B2 (en) * | 2000-01-27 | 2004-01-13 | David C. Baskett | Crossover tree system |
US20040026084A1 (en) * | 2000-11-08 | 2004-02-12 | Ian Donald | Recovery of production fluids from an oil or gas well |
US6763890B2 (en) * | 2002-06-04 | 2004-07-20 | Schlumberger Technology Corporation | Modular coiled tubing system for drilling and production platforms |
US6902005B2 (en) * | 2002-02-15 | 2005-06-07 | Vetco Gray Inc. | Tubing annulus communication for vertical flow subsea well |
US6907932B2 (en) * | 2003-01-27 | 2005-06-21 | Drill-Quip, Inc. | Control pod latchdown mechanism |
US6966383B2 (en) * | 2002-12-12 | 2005-11-22 | Dril-Quip, Inc. | Horizontal spool tree with improved porting |
US7073592B2 (en) * | 2002-06-04 | 2006-07-11 | Schlumberger Technology Corporation | Jacking frame for coiled tubing operations |
US7201229B2 (en) * | 2003-10-22 | 2007-04-10 | Vetco Gray Inc. | Tree mounted well flow interface device |
US7243729B2 (en) * | 2004-10-19 | 2007-07-17 | Oceaneering International, Inc. | Subsea junction plate assembly running tool and method of installation |
US20080047714A1 (en) * | 2006-08-28 | 2008-02-28 | Mcmiles Barry James | High pressure large bore utility line connector assembly |
US20090025936A1 (en) * | 2004-02-26 | 2009-01-29 | Des Enhanced Recovery Limited | Connection system for subsea flow interface equipment |
US20100300700A1 (en) * | 2006-08-18 | 2010-12-02 | Cameron International Corporation | Wellhead Assembly |
Family Cites Families (163)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US201956A (en) * | 1878-04-02 | Improvement in sash-holders | ||
GB242913A (en) | 1925-06-25 | 1925-11-19 | Albert Wainman | Improvements in convertible settees |
US2415992A (en) | 1943-09-25 | 1947-02-18 | Louis C Clair | Gas pressure reducing means |
GB1022352A (en) | 1961-06-25 | 1966-03-09 | Ass Elect Ind | Improvements relating to intercoolers for rotary gas compressors |
US3962356A (en) * | 1963-10-24 | 1976-06-08 | Monsanto Chemicals Limited | Substituted cyclopropanes |
US3664376A (en) * | 1970-01-26 | 1972-05-23 | Regan Forge & Eng Co | Flow line diverter apparatus |
US3753257A (en) * | 1972-02-28 | 1973-08-14 | Atlantic Richfield Co | Well monitoring for production of solids |
JPS527499B2 (en) * | 1973-01-24 | 1977-03-02 | ||
US4125345A (en) | 1974-09-20 | 1978-11-14 | Hitachi, Ltd. | Turbo-fluid device |
US4090366A (en) | 1976-05-12 | 1978-05-23 | Vickers-Intertek Limited | Transit capsules |
US4120362A (en) | 1976-11-22 | 1978-10-17 | Societe Nationale Elf Aquitaine (Production) | Subsea station |
AU498216B2 (en) | 1977-03-21 | 1979-02-22 | Exxon Production Research Co | Blowout preventer bypass |
US4106562A (en) * | 1977-05-16 | 1978-08-15 | Union Oil Company Of California | Wellhead apparatus |
US4105068A (en) | 1977-07-29 | 1978-08-08 | Chicago Bridge & Iron Company | Apparatus for producing oil and gas offshore |
US4102401A (en) | 1977-09-06 | 1978-07-25 | Exxon Production Research Company | Well treatment fluid diversion with low density ball sealers |
US4161367A (en) | 1978-02-15 | 1979-07-17 | Fmc Corporation | Method and apparatus for completing diverless subsea flowline connections |
JPS5919883Y2 (en) | 1980-03-19 | 1984-06-08 | 日立建機株式会社 | annular heat exchanger |
US4450016A (en) * | 1981-07-10 | 1984-05-22 | Santrade Ltd. | Method of manufacturing cladding tubes of a zirconium-based alloy for fuel rods for nuclear reactors |
CH638019A5 (en) | 1982-04-08 | 1983-08-31 | Sulzer Ag | Compressor system |
GB8505327D0 (en) | 1985-03-01 | 1985-04-03 | Texaco Ltd | Subsea well head template |
US4630681A (en) | 1985-02-25 | 1986-12-23 | Decision-Tree Associates, Inc. | Multi-well hydrocarbon development system |
GB8505328D0 (en) | 1985-03-01 | 1985-04-03 | Texaco Ltd | Subsea well head allignment system |
US4629003A (en) | 1985-08-01 | 1986-12-16 | Baugh Benton F | Guilelineless subsea completion system with horizontal flowline connection |
US4706933A (en) * | 1985-09-27 | 1987-11-17 | Sukup Richard A | Oil and gas well safety valve |
CN1011432B (en) | 1986-01-13 | 1991-01-30 | 三菱重工业株式会社 | Extracting method of special crude oil |
US4695190A (en) | 1986-03-04 | 1987-09-22 | Smith International, Inc. | Pressure-balanced stab connection |
JPS634197A (en) | 1986-06-25 | 1988-01-09 | 三菱重工業株式会社 | Method of drilling special crude oil |
US4702320A (en) | 1986-07-31 | 1987-10-27 | Otis Engineering Corporation | Method and system for attaching and removing equipment from a wellhead |
NO175020C (en) | 1986-08-04 | 1994-08-17 | Norske Stats Oljeselskap | Method of transporting untreated well stream |
GB8623900D0 (en) | 1986-10-04 | 1986-11-05 | British Petroleum Co Plc | Subsea oil production system |
GB8627489D0 (en) | 1986-11-18 | 1986-12-17 | British Petroleum Co Plc | Stimulating oil production |
US4896725A (en) | 1986-11-25 | 1990-01-30 | Parker Marvin T | In-well heat exchange method for improved recovery of subterranean fluids with poor flowability |
GB8707307D0 (en) | 1987-03-26 | 1987-04-29 | British Petroleum Co Plc | Sea bed process complex |
US4813495A (en) | 1987-05-05 | 1989-03-21 | Conoco Inc. | Method and apparatus for deepwater drilling |
GB2209361A (en) | 1987-09-04 | 1989-05-10 | Autocon Ltd | Controlling underwater installations |
US4830111A (en) | 1987-09-09 | 1989-05-16 | Jenkins Jerold D | Water well treating method |
US4820083A (en) | 1987-10-28 | 1989-04-11 | Amoco Corporation | Flexible flowline connection to a subsea wellhead assembly |
DE3738424A1 (en) | 1987-11-12 | 1989-05-24 | Dreier Werk Gmbh | Shower cubicle as prefabricated unit |
US4911240A (en) | 1987-12-28 | 1990-03-27 | Haney Robert C | Self treating paraffin removing apparatus and method |
NO890467D0 (en) | 1989-02-06 | 1989-02-06 | Sinvent As | HYDRAULIC DRIVE Piston Pump for Multiphase Flow Compression. |
US4972904A (en) | 1989-08-24 | 1990-11-27 | Foster Oilfield Equipment Co. | Geothermal well chemical injection system |
US4926898A (en) | 1989-10-23 | 1990-05-22 | Sampey Ted J | Safety choke valve |
GB8925075D0 (en) | 1989-11-07 | 1989-12-28 | British Petroleum Co Plc | Sub-sea well injection system |
US5044672A (en) | 1990-03-22 | 1991-09-03 | Fmc Corporation | Metal-to-metal sealing pipe swivel joint |
US5069286A (en) | 1990-04-30 | 1991-12-03 | The Mogul Corporation | Method for prevention of well fouling |
GB9014237D0 (en) | 1990-06-26 | 1990-08-15 | Framo Dev Ltd | Subsea pump system |
SE500042C2 (en) | 1990-08-31 | 1994-03-28 | Eka Nobel Ab | Process for continuous production of chlorine dioxide |
JPH04125977A (en) | 1990-09-17 | 1992-04-27 | Nec Corp | Heteromultiple structure avalanche photodiode |
BR9005132A (en) | 1990-10-12 | 1992-04-14 | Petroleo Brasileiro Sa | SUBMARINE CONNECTION SYSTEM AND ACTIVE CONNECTOR USED IN THIS SYSTEM |
US5074519A (en) | 1990-11-09 | 1991-12-24 | Cooper Industries, Inc. | Fail-close hydraulically actuated control choke |
FR2672935B1 (en) | 1991-02-14 | 1999-02-26 | Elf Aquitaine | UNDERWATER WELL HEAD. |
BR9103428A (en) | 1991-08-09 | 1993-03-09 | Petroleo Brasileiro Sa | WET CHRISTMAS TREE |
BR9103429A (en) | 1991-08-09 | 1993-03-09 | Petroleo Brasileiro Sa | SATELLITE TREE MODULE AND STRUCTURE OF FLOW LINES FOR INTERCONNECTING A SATELLITE POCO TO A SUBMARINE PRODUCTION SYSTEM |
US5201491A (en) | 1992-02-21 | 1993-04-13 | Texaco Inc. | Adjustable well choke mechanism |
US5248166A (en) | 1992-03-31 | 1993-09-28 | Cooper Industries, Inc. | Flowline safety joint |
EP0568742A1 (en) | 1992-05-08 | 1993-11-10 | Cooper Industries, Inc. | Transfer of production fluid from a well |
US5255745A (en) | 1992-06-18 | 1993-10-26 | Cooper Industries, Inc. | Remotely operable horizontal connection apparatus and method |
US5377762A (en) | 1993-02-09 | 1995-01-03 | Cooper Industries, Inc. | Bore selector |
GB9311583D0 (en) | 1993-06-04 | 1993-07-21 | Cooper Ind Inc | Modular control system |
JPH0783266A (en) | 1993-09-14 | 1995-03-28 | Nippon Seiko Kk | Electric viscous fluid damper for slide mechanism |
FR2710946B1 (en) | 1993-10-06 | 2001-06-15 | Inst Francais Du Petrole | Energy generation and transfer system. |
GB2282863B (en) | 1993-10-14 | 1997-06-18 | Vinten Group Plc | Improvements in or relating to apparatus mountings providing at least one axis of movement with damping |
NO309442B1 (en) | 1994-05-06 | 2001-01-29 | Abb Offshore Systems As | System and method for withdrawal and interconnection of two submarine pipelines |
US5553514A (en) | 1994-06-06 | 1996-09-10 | Stahl International, Inc. | Active torsional vibration damper |
KR0129664Y1 (en) | 1994-06-30 | 1999-01-15 | 김광호 | Damping device for a robot |
GB9418088D0 (en) | 1994-09-08 | 1994-10-26 | Exploration & Prod Serv | Horizontal subsea tree pressure compensated plug |
US5762149A (en) * | 1995-03-27 | 1998-06-09 | Baker Hughes Incorporated | Method and apparatus for well bore construction |
GB9514510D0 (en) | 1995-07-15 | 1995-09-13 | Expro North Sea Ltd | Lightweight intervention system |
US5730551A (en) | 1995-11-14 | 1998-03-24 | Fmc Corporation | Subsea connector system and method for coupling subsea conduits |
US5649594A (en) | 1995-12-11 | 1997-07-22 | Boots & Coots, L.P. | Method and apparatus for servicing a wellhead assembly |
US6457540B2 (en) | 1996-02-01 | 2002-10-01 | Robert Gardes | Method and system for hydraulic friction controlled drilling and completing geopressured wells utilizing concentric drill strings |
JP3729563B2 (en) | 1996-06-24 | 2005-12-21 | 陽一 遠藤 | Bicycle saddle |
WO1998015712A2 (en) | 1996-10-08 | 1998-04-16 | Baker Hughes Incorporated | Method of forming wellbores from a main wellbore |
US20010011593A1 (en) | 1996-11-06 | 2001-08-09 | Wilkins Robert Lee | Well completion system with an annular bypass and a solid stopper means |
GB2320937B (en) * | 1996-12-02 | 2000-09-20 | Vetco Gray Inc Abb | Horizontal tree block for subsea wellhead |
US5988282A (en) | 1996-12-26 | 1999-11-23 | Abb Vetco Gray Inc. | Pressure compensated actuated check valve |
US5967235A (en) | 1997-04-01 | 1999-10-19 | Halliburton Energy Services, Inc. | Wellhead union with safety interlock |
US6388577B1 (en) | 1997-04-07 | 2002-05-14 | Kenneth J. Carstensen | High impact communication and control system |
US6289992B1 (en) | 1997-06-13 | 2001-09-18 | Abb Vetco Gray, Inc. | Variable pressure pump through nozzle |
US5927405A (en) | 1997-06-13 | 1999-07-27 | Abb Vetco Gray, Inc. | Casing annulus remediation system |
US6098715A (en) | 1997-07-30 | 2000-08-08 | Abb Vetco Gray Inc. | Flowline connection system |
WO1999006731A1 (en) | 1997-08-04 | 1999-02-11 | Lord Corporation | Magnetorheological fluid devices exhibiting settling stability |
DE19738697C1 (en) | 1997-08-29 | 1998-11-26 | Siemens Ag | High voltage load switch with driven counter contact piece |
US6182761B1 (en) | 1997-11-12 | 2001-02-06 | Exxonmobil Upstream Research Company | Flowline extendable pigging valve assembly |
US6236645B1 (en) * | 1998-03-09 | 2001-05-22 | Broadcom Corporation | Apparatus for, and method of, reducing noise in a communications system |
US6230824B1 (en) * | 1998-03-27 | 2001-05-15 | Hydril Company | Rotating subsea diverter |
US6186239B1 (en) | 1998-05-13 | 2001-02-13 | Abb Vetco Gray Inc. | Casing annulus remediation system |
US7270185B2 (en) | 1998-07-15 | 2007-09-18 | Baker Hughes Incorporated | Drilling system and method for controlling equivalent circulating density during drilling of wellbores |
US6321843B2 (en) | 1998-07-23 | 2001-11-27 | Cooper Cameron Corporation | Preloading type connector |
US6123312A (en) | 1998-11-16 | 2000-09-26 | Dai; Yuzhong | Proactive shock absorption and vibration isolation |
US6352114B1 (en) | 1998-12-11 | 2002-03-05 | Ocean Drilling Technology, L.L.C. | Deep ocean riser positioning system and method of running casing |
GB2345929B (en) | 1998-12-18 | 2002-09-11 | Vetco Gray Inc Abb | Tree cap with shuttle valve |
US6116784A (en) | 1999-01-07 | 2000-09-12 | Brotz; Gregory R. | Dampenable bearing |
CA2362810A1 (en) | 1999-02-11 | 2000-08-17 | Fmc Corporation | Subsea completion apparatus |
GB2346630B (en) | 1999-02-11 | 2001-08-08 | Fmc Corp | Flow control package for subsea completions |
GB2349662B (en) * | 1999-02-11 | 2001-01-31 | Fmc Corp | Large bore subsea christmas tree and tubing hanger system |
JP2000251035A (en) | 1999-02-26 | 2000-09-14 | Hitachi Ltd | Memory card |
US6302249B1 (en) | 1999-03-08 | 2001-10-16 | Lord Corporation | Linear-acting controllable pneumatic actuator and motion control apparatus including a field responsive medium and control method therefor |
US7111687B2 (en) | 1999-05-14 | 2006-09-26 | Des Enhanced Recovery Limited | Recovery of production fluids from an oil or gas well |
US6296453B1 (en) | 1999-08-23 | 2001-10-02 | James Layman | Production booster in a flow line choke |
US6450262B1 (en) | 1999-12-09 | 2002-09-17 | Stewart & Stevenson Services, Inc. | Riser isolation tool |
US6457529B2 (en) * | 2000-02-17 | 2002-10-01 | Abb Vetco Gray Inc. | Apparatus and method for returning drilling fluid from a subsea wellbore |
GB2361726B (en) | 2000-04-27 | 2002-05-08 | Fmc Corp | Coiled tubing line deployment system |
GB0020460D0 (en) | 2000-08-18 | 2000-10-11 | Alpha Thames Ltd | A system suitable for use on a seabed and a method of installing it |
US6494267B2 (en) | 2000-11-29 | 2002-12-17 | Cooper Cameron Corporation | Wellhead assembly for accessing an annulus in a well and a method for its use |
US6516861B2 (en) * | 2000-11-29 | 2003-02-11 | Cooper Cameron Corporation | Method and apparatus for injecting a fluid into a well |
US6484807B2 (en) | 2000-11-29 | 2002-11-26 | Cooper Cameron Corporation | Wellhead assembly for injecting a fluid into a well and method of using the same |
US7040408B2 (en) | 2003-03-11 | 2006-05-09 | Worldwide Oilfield Machine, Inc. | Flowhead and method |
US6457530B1 (en) | 2001-03-23 | 2002-10-01 | Stream-Flo Industries, Ltd. | Wellhead production pumping tree |
GB0108086D0 (en) | 2001-03-30 | 2001-05-23 | Norske Stats Oljeselskap | Method |
GB0110398D0 (en) * | 2001-04-27 | 2001-06-20 | Alpha Thames Ltd | Wellhead product testing system |
EP1255028A3 (en) * | 2001-05-03 | 2005-05-11 | Kautex Textron GmbH & Co. KG. | Blow molded support |
US6755254B2 (en) | 2001-05-25 | 2004-06-29 | Dril-Quip, Inc. | Horizontal spool tree assembly |
US6575247B2 (en) | 2001-07-13 | 2003-06-10 | Exxonmobil Upstream Research Company | Device and method for injecting fluids into a wellbore |
NO325717B1 (en) | 2001-07-27 | 2008-07-07 | Vetco Gray Inc | Production tree with triple safety barrier and procedures using the same |
US6805200B2 (en) | 2001-08-20 | 2004-10-19 | Dril-Quip, Inc. | Horizontal spool tree wellhead system and method |
GB0124612D0 (en) | 2001-10-12 | 2001-12-05 | Alpha Thames Ltd | Single well development system |
NO332032B1 (en) * | 2001-11-21 | 2012-05-29 | Vetco Gray Inc | Underwater wellhead assembly and method of completing an underwater well |
CA2363974C (en) | 2001-11-26 | 2004-12-14 | Harry Richard Cove | Insert assembly for a wellhead choke valve |
US6742594B2 (en) | 2002-02-06 | 2004-06-01 | Abb Vetco Gray Inc. | Flowline jumper for subsea well |
US6719059B2 (en) | 2002-02-06 | 2004-04-13 | Abb Vetco Gray Inc. | Plug installation system for deep water subsea wells |
NO315912B1 (en) | 2002-02-28 | 2003-11-10 | Abb Offshore Systems As | Underwater separation device for processing crude oil comprising a separator module with a separator tank |
US6651745B1 (en) | 2002-05-02 | 2003-11-25 | Union Oil Company Of California | Subsea riser separator system |
US6840323B2 (en) | 2002-06-05 | 2005-01-11 | Abb Vetco Gray Inc. | Tubing annulus valve |
CA2404315A1 (en) | 2002-09-20 | 2004-03-20 | Dean Edward Moan | Well servicing apparatus and method |
GB2420809B (en) | 2002-11-12 | 2006-12-13 | Vetco Gray Inc | Drilling and producing deep water subsea wells |
NO320179B1 (en) | 2002-12-27 | 2005-11-07 | Vetco Aibel As | underwater System |
US6851478B2 (en) | 2003-02-07 | 2005-02-08 | Stream-Flo Industries, Ltd. | Y-body Christmas tree for use with coil tubing |
CA2423645A1 (en) | 2003-03-28 | 2004-09-28 | Larry Bunney | Manifold device and method of use for accessing a casing annulus of a well |
US7069995B2 (en) | 2003-04-16 | 2006-07-04 | Vetco Gray Inc. | Remedial system to flush contaminants from tubing string |
ATE482324T1 (en) | 2003-05-31 | 2010-10-15 | Cameron Systems Ireland Ltd | APPARATUS AND METHOD FOR RECOVERING LIQUIDS FROM A BOREHOLE AND/OR FOR INJECTING LIQUIDS INTO A BOREHOLE |
US6948909B2 (en) | 2003-09-16 | 2005-09-27 | Modine Manufacturing Company | Formed disk plate heat exchanger |
EP1518595B1 (en) | 2003-09-24 | 2012-02-22 | Cameron International Corporation | Subsea well production flow and separation system |
DE602004026905D1 (en) | 2003-10-23 | 2010-06-10 | Ab Science | 2-AMINOARYLOXAZOLE COMPOUNDS AS TYROSINE KINASE INHIBITORS |
NZ546645A (en) | 2003-10-23 | 2010-02-26 | Ab Science | 2-Aminoaryloxazole compounds as tyrosine kinase inhibitors |
WO2005047639A2 (en) | 2003-11-05 | 2005-05-26 | Fmc Technologies, Inc. | Subsea completion system and method of using same |
US7000638B2 (en) | 2004-01-26 | 2006-02-21 | Honeywell International. Inc. | Diverter valve with multiple valve seat rings |
EP1574773A2 (en) * | 2004-03-10 | 2005-09-14 | Calsonic Kansei Corporation | Y-shaped branching pipe of a bouble walled pipe and method of making the same |
US7331396B2 (en) | 2004-03-16 | 2008-02-19 | Dril-Quip, Inc. | Subsea production systems |
US7823648B2 (en) | 2004-10-07 | 2010-11-02 | Bj Services Company, U.S.A. | Downhole safety valve apparatus and method |
NO323513B1 (en) | 2005-03-11 | 2007-06-04 | Well Technology As | Device and method for subsea deployment and / or intervention through a wellhead of a petroleum well by means of an insertion device |
US7658228B2 (en) | 2005-03-15 | 2010-02-09 | Ocean Riser System | High pressure system |
AU2006254948B2 (en) | 2005-06-08 | 2009-12-10 | Baker Hughes Incorporated | Wellhead bypass method and apparatus |
JP4828605B2 (en) | 2005-08-02 | 2011-11-30 | トランスオーシャン オフショア ディープウォーター ドリリング, インコーポレイテッド | Modular backup fluid supply system |
WO2007075860A2 (en) | 2005-12-19 | 2007-07-05 | Mundell Bret M | Gas wellhead extraction system and method |
CN101351647B (en) | 2005-12-30 | 2011-05-18 | 英格索尔-兰德公司 | Geared inlet guide vane for a centrifugal compressor |
US7909103B2 (en) | 2006-04-20 | 2011-03-22 | Vetcogray Inc. | Retrievable tubing hanger installed below tree |
EP2016254B1 (en) | 2006-05-08 | 2017-03-22 | Mako Rentals, Inc. | Downhole swivel apparatus and method |
US7569097B2 (en) | 2006-05-26 | 2009-08-04 | Curtiss-Wright Electro-Mechanical Corporation | Subsea multiphase pumping systems |
US7699099B2 (en) | 2006-08-02 | 2010-04-20 | B.J. Services Company, U.S.A. | Modified Christmas tree components and associated methods for using coiled tubing in a well |
GB0618001D0 (en) | 2006-09-13 | 2006-10-18 | Des Enhanced Recovery Ltd | Method |
US20080128139A1 (en) | 2006-11-09 | 2008-06-05 | Vetco Gray Inc. | Utility skid tree support system for subsea wellhead |
GB0625526D0 (en) | 2006-12-18 | 2007-01-31 | Des Enhanced Recovery Ltd | Apparatus and method |
GB0625191D0 (en) | 2006-12-18 | 2007-01-24 | Des Enhanced Recovery Ltd | Apparatus and method |
AU2008206518B2 (en) | 2007-01-12 | 2011-06-09 | Bj Services Company | Wellhead assembly and method for an injection tubing string |
US8011436B2 (en) | 2007-04-05 | 2011-09-06 | Vetco Gray Inc. | Through riser installation of tree block |
US7596996B2 (en) * | 2007-04-19 | 2009-10-06 | Fmc Technologies, Inc. | Christmas tree with internally positioned flowmeter |
US20080302535A1 (en) | 2007-06-08 | 2008-12-11 | David Barnes | Subsea Intervention Riser System |
BRPI0806027B1 (en) | 2007-11-19 | 2019-01-29 | Vetco Gray Inc | undersea tree |
US8573307B2 (en) | 2008-04-21 | 2013-11-05 | Ocean Riser Systems As | High pressure sleeve for dual bore HP riser |
SG10201503033PA (en) | 2008-04-25 | 2015-06-29 | Vetco Gray Inc | Subsea toroidal water separator |
US20100018693A1 (en) | 2008-07-25 | 2010-01-28 | Neil Sutherland Duncan | Pipeline entry system |
US8672038B2 (en) | 2010-02-10 | 2014-03-18 | Magnum Subsea Systems Pte Ltd. | Retrievable subsea bridge tree assembly and method |
-
2004
- 2004-06-01 AT AT08162149T patent/ATE482324T1/en not_active IP Right Cessation
- 2004-06-01 EP EP08162149A patent/EP1990505B1/en not_active Expired - Lifetime
- 2004-06-01 DE DE602004019212T patent/DE602004019212D1/en not_active Expired - Fee Related
- 2004-06-01 AT AT08000994T patent/ATE446437T1/en not_active IP Right Cessation
- 2004-06-01 EP EP10161117.6A patent/EP2216503B1/en not_active Expired - Lifetime
- 2004-06-01 CA CA2526714A patent/CA2526714C/en not_active Expired - Lifetime
- 2004-06-01 EP EP10185795.1A patent/EP2282004B1/en not_active Expired - Lifetime
- 2004-06-01 EP EP08000994A patent/EP1918509B1/en not_active Expired - Lifetime
- 2004-06-01 US US10/558,593 patent/US7992643B2/en active Active - Reinstated
- 2004-06-01 EP EP10167181.6A patent/EP2230378B1/en not_active Expired - Lifetime
- 2004-06-01 EP EP17186597.5A patent/EP3272995B1/en not_active Expired - Lifetime
- 2004-06-01 EP EP10185612.8A patent/EP2273066B1/en not_active Expired - Lifetime
- 2004-06-01 EP EP10167184.0A patent/EP2233688B1/en not_active Expired - Lifetime
- 2004-06-01 EP EP10161120.0A patent/EP2221450B1/en not_active Expired - Lifetime
- 2004-06-01 EP EP04735596A patent/EP1639230B1/en not_active Expired - Lifetime
- 2004-06-01 EP EP10167183.2A patent/EP2233687B1/en not_active Expired - Lifetime
- 2004-06-01 EP EP10013192.9A patent/EP2287438B1/en not_active Expired - Lifetime
- 2004-06-01 BR BRPI0410869A patent/BRPI0410869B1/en active IP Right Grant
- 2004-06-01 EP EP10161116.8A patent/EP2216502B1/en not_active Expired - Lifetime
- 2004-06-01 EA EA200600002A patent/EA009139B1/en not_active IP Right Cessation
- 2004-06-01 DE DE602004029295T patent/DE602004029295D1/en not_active Expired - Lifetime
- 2004-06-01 EP EP10167182.4A patent/EP2233686B1/en not_active Expired - Lifetime
- 2004-06-01 AU AU2004289864A patent/AU2004289864B2/en not_active Expired
- 2004-06-01 AT AT04735596T patent/ATE421631T1/en not_active IP Right Cessation
- 2004-06-01 WO PCT/GB2004/002329 patent/WO2005047646A1/en active Application Filing
- 2004-06-01 DE DE602004023775T patent/DE602004023775D1/en not_active Expired - Fee Related
-
2005
- 2005-12-22 NO NO20056144A patent/NO343392B1/en unknown
-
2009
- 2009-08-15 US US12/541,934 patent/US8272435B2/en active Active
- 2009-08-15 US US12/541,936 patent/US7992633B2/en not_active Expired - Fee Related
- 2009-08-15 US US12/541,938 patent/US8066067B2/en not_active Expired - Fee Related
- 2009-08-15 US US12/541,937 patent/US8281864B2/en not_active Expired - Lifetime
-
2010
- 2010-04-27 US US12/768,337 patent/US8122948B2/en not_active Expired - Fee Related
- 2010-04-27 US US12/768,324 patent/US8220535B2/en not_active Expired - Lifetime
- 2010-04-27 US US12/768,332 patent/US8091630B2/en not_active Expired - Fee Related
-
2011
- 2011-01-17 AU AU2011200165A patent/AU2011200165B2/en not_active Expired
- 2011-05-26 US US13/116,889 patent/US8167049B2/en not_active Expired - Fee Related
- 2011-06-20 US US13/164,291 patent/US8469086B2/en not_active Expired - Lifetime
- 2011-08-08 US US13/205,284 patent/US8622138B2/en not_active Expired - Lifetime
-
2012
- 2012-02-27 US US13/405,997 patent/US8573306B2/en not_active Expired - Lifetime
- 2012-03-08 US US13/415,635 patent/US8746332B2/en not_active Expired - Fee Related
- 2012-06-28 US US13/536,433 patent/US8540018B2/en not_active Expired - Lifetime
- 2012-11-28 US US13/687,290 patent/US8733436B2/en not_active Expired - Lifetime
-
2014
- 2014-05-01 US US14/266,936 patent/US10107069B2/en active Active
- 2014-05-22 US US14/285,114 patent/US9556710B2/en not_active Expired - Fee Related
-
2017
- 2017-01-27 US US15/418,368 patent/US10415346B2/en not_active Expired - Fee Related
Patent Citations (99)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US1758376A (en) * | 1926-01-09 | 1930-05-13 | Nelson E Reynolds | Method and means to pump oil with fluids |
US1994840A (en) * | 1930-05-27 | 1935-03-19 | Caterpillar Tractor Co | Chain |
US1944573A (en) * | 1931-10-12 | 1934-01-23 | William A Raymond | Control head |
US1944840A (en) * | 1933-02-24 | 1934-01-23 | Margia Manning | Control head for wells |
US2132199A (en) * | 1936-10-12 | 1938-10-04 | Gray Tool Co | Well head installation with choke valve |
US2276883A (en) * | 1937-05-18 | 1942-03-17 | Standard Catalytic Co | Apparatus for preheating liquid carbonaceous material |
US2233077A (en) * | 1938-10-10 | 1941-02-25 | Barker | Well controlling apparatus |
US2412765A (en) * | 1941-07-25 | 1946-12-17 | Phillips Petroleum Co | Recovery of hydrocarbons |
US2962356A (en) * | 1953-09-09 | 1960-11-29 | Monsanto Chemicals | Corrosion inhibition |
US2790500A (en) * | 1954-03-24 | 1957-04-30 | Edward N Jones | Pump for propelling pellets into oil wells for treating the same |
US2893435A (en) * | 1956-02-03 | 1959-07-07 | Mcevoy Co | Choke |
US3101118A (en) * | 1959-08-17 | 1963-08-20 | Shell Oil Co | Y-branched wellhead assembly |
US3163224A (en) * | 1962-04-20 | 1964-12-29 | Shell Oil Co | Underwater well drilling apparatus |
US3378066A (en) * | 1965-09-30 | 1968-04-16 | Shell Oil Co | Underwater wellhead connection |
US3358753A (en) * | 1965-12-30 | 1967-12-19 | Shell Oil Co | Underwater flowline installation |
US3595311A (en) * | 1967-01-19 | 1971-07-27 | Inst Francais Du Petrole | Connecting unit for the completion equipment of a producing underwater well |
US3608631A (en) * | 1967-11-14 | 1971-09-28 | Otis Eng Co | Apparatus for pumping tools into and out of a well |
US3593808A (en) * | 1969-01-07 | 1971-07-20 | Arthur J Nelson | Apparatus and method for drilling underwater |
US3603409A (en) * | 1969-03-27 | 1971-09-07 | Regan Forge & Eng Co | Method and apparatus for balancing subsea internal and external well pressures |
US3710859A (en) * | 1970-05-27 | 1973-01-16 | Vetco Offshore Ind Inc | Apparatus for remotely connecting and disconnecting pipe lines to and from a submerged wellhead |
US3705626A (en) * | 1970-11-19 | 1972-12-12 | Mobil Oil Corp | Oil well flow control method |
US3688840A (en) * | 1971-02-16 | 1972-09-05 | Cameron Iron Works Inc | Method and apparatus for use in drilling a well |
US3777812A (en) * | 1971-11-26 | 1973-12-11 | Exxon Production Research Co | Subsea production system |
US3834460A (en) * | 1971-12-27 | 1974-09-10 | Subsea Equipment Ass Ltd | Well-head assembly |
US3820558A (en) * | 1973-01-11 | 1974-06-28 | Rex Chainbelt Inc | Combination valve |
US3953982A (en) * | 1973-12-05 | 1976-05-04 | Subsea Equipment Associates Limited | Method and apparatus for laying and connecting flow lines to submerged structures |
US3957079A (en) * | 1975-01-06 | 1976-05-18 | C. Jim Stewart & Stevenson, Inc. | Valve assembly for a subsea well control system |
US4046192A (en) * | 1975-06-13 | 1977-09-06 | Seal Petroleum Limited | Method and apparatus for installing a control valve assembly on an underwater well head |
US4046191A (en) * | 1975-07-07 | 1977-09-06 | Exxon Production Research Company | Subsea hydraulic choke |
US4042033A (en) * | 1976-10-01 | 1977-08-16 | Exxon Production Research Company | Combination subsurface safety valve and chemical injector valve |
US4120363A (en) * | 1976-11-26 | 1978-10-17 | Arnold E. Ernst | Root crop harvester |
US4095649A (en) * | 1977-01-13 | 1978-06-20 | Societe Nationale Elf Aquitaine (Production) | Reentry system for subsea well apparatus |
US4099583A (en) * | 1977-04-11 | 1978-07-11 | Exxon Production Research Company | Gas lift system for marine drilling riser |
US4274664A (en) * | 1977-08-05 | 1981-06-23 | Compagnie Francaise Des Petroles | Pipe joining device for underseas petroleum pipeline |
US4190120A (en) * | 1977-11-18 | 1980-02-26 | Regan Offshore International, Inc. | Moveable guide structure for a sub-sea drilling template |
US4260022A (en) * | 1978-09-22 | 1981-04-07 | Vetco, Inc. | Through the flow-line selector apparatus and method |
US4223728A (en) * | 1978-11-30 | 1980-09-23 | Garrett Energy Research & Engineering Inc. | Method of oil recovery from underground reservoirs |
US4210208A (en) * | 1978-12-04 | 1980-07-01 | Sedco, Inc. | Subsea choke and riser pressure equalization system |
US4294471A (en) * | 1979-11-30 | 1981-10-13 | Vetco Inc. | Subsea flowline connector |
US4291772A (en) * | 1980-03-25 | 1981-09-29 | Standard Oil Company (Indiana) | Drilling fluid bypass for marine riser |
US4403658A (en) * | 1980-09-04 | 1983-09-13 | Hughes Tool Company | Multiline riser support and connection system and method for subsea wells |
US4405016A (en) * | 1980-12-18 | 1983-09-20 | Smith International, Inc. | Underwater Christmas tree cap and lockdown apparatus |
US4347899A (en) * | 1980-12-19 | 1982-09-07 | Mobil Oil Corporation | Downhold injection of well-treating chemical during production by gas lift |
US4401164A (en) * | 1981-04-24 | 1983-08-30 | Baugh Benton F | In situ method and apparatus for inspecting and repairing subsea wellheads |
US4457489A (en) * | 1981-07-13 | 1984-07-03 | Gilmore Samuel E | Subsea fluid conduit connections for remote controlled valves |
US4444275A (en) * | 1981-12-02 | 1984-04-24 | Standard Oil Company | Carousel for vertically moored platform |
US4509599A (en) * | 1982-10-01 | 1985-04-09 | Baker Oil Tools, Inc. | Gas well liquid removal system and process |
US4572298A (en) * | 1982-11-05 | 1986-02-25 | Hydril Company | Gate valve apparatus and method |
US4502534A (en) * | 1982-12-13 | 1985-03-05 | Hydril Company | Flow diverter |
US4478287A (en) * | 1983-01-27 | 1984-10-23 | Hydril Company | Well control method and apparatus |
US4503878A (en) * | 1983-04-29 | 1985-03-12 | Cameron Iron Works, Inc. | Choke valve |
US4589493A (en) * | 1984-04-02 | 1986-05-20 | Cameron Iron Works, Inc. | Subsea wellhead production apparatus with a retrievable subsea choke |
US4626135A (en) * | 1984-10-22 | 1986-12-02 | Hydril Company | Marine riser well control method and apparatus |
US4607701A (en) * | 1984-11-01 | 1986-08-26 | Vetco Offshore Industries, Inc. | Tree control manifold |
US4610570A (en) * | 1984-11-27 | 1986-09-09 | Vickers Public Limited Company | Marine anchors |
US4646844A (en) * | 1984-12-24 | 1987-03-03 | Hydril Company | Diverter/bop system and method for a bottom supported offshore drilling rig |
US4648629A (en) * | 1985-05-01 | 1987-03-10 | Vetco Offshore, Inc. | Underwater connector |
US4749046A (en) * | 1986-05-28 | 1988-06-07 | Otis Engineering Corporation | Well drilling and completion apparatus |
US4848473A (en) * | 1987-12-21 | 1989-07-18 | Chevron Research Company | Subsea well choke system |
US4874008A (en) * | 1988-04-20 | 1989-10-17 | Cameron Iron Works U.S.A., Inc. | Valve mounting and block manifold |
US5010956A (en) * | 1990-03-28 | 1991-04-30 | Exxon Production Research Company | Subsea tree cap well choke system |
US5143158A (en) * | 1990-04-27 | 1992-09-01 | Dril-Quip, Inc. | Subsea wellhead apparatus |
US5295534A (en) * | 1991-04-15 | 1994-03-22 | Texaco Inc. | Pressure monitoring of a producing well |
US5544707A (en) * | 1992-06-01 | 1996-08-13 | Cooper Cameron Corporation | Wellhead |
US5535826A (en) * | 1992-06-17 | 1996-07-16 | Petroleum Engineering Services Limited | Well-head structures |
US5398761A (en) * | 1993-05-03 | 1995-03-21 | Syntron, Inc. | Subsea blowout preventer modular control pod |
US5492436A (en) * | 1994-04-14 | 1996-02-20 | Pool Company | Apparatus and method for moving rig structures |
US5526882A (en) * | 1995-01-19 | 1996-06-18 | Sonsub, Inc. | Subsea drilling and production template system |
US6109352A (en) * | 1995-09-23 | 2000-08-29 | Expro North Sea Limited | Simplified Xmas tree using sub-sea test tree |
US6209650B1 (en) * | 1996-08-27 | 2001-04-03 | Den Norske Stats Oljeselskap As | Subsea well |
US5971077A (en) * | 1996-11-22 | 1999-10-26 | Abb Vetco Gray Inc. | Insert tree |
US5992527A (en) * | 1996-11-29 | 1999-11-30 | Cooper Cameron Corporation | Wellhead assembly |
US6050339A (en) * | 1996-12-06 | 2000-04-18 | Abb Vetco Gray Inc. | Annulus porting of horizontal tree |
US5868204A (en) * | 1997-05-08 | 1999-02-09 | Abb Vetco Gray Inc. | Tubing hanger vent |
US6227300B1 (en) * | 1997-10-07 | 2001-05-08 | Fmc Corporation | Slimbore subsea completion system and method |
US5992526A (en) * | 1997-12-03 | 1999-11-30 | Fmc Corporation | ROV deployed tree cap for a subsea tree and method of installation |
US6138774A (en) * | 1998-03-02 | 2000-10-31 | Weatherford Holding U.S., Inc. | Method and apparatus for drilling a borehole into a subsea abnormal pore pressure environment |
US6497286B1 (en) * | 1998-03-27 | 2002-12-24 | Cooper Cameron Corporation | Method and apparatus for drilling a plurality of offshore underwater wells |
US6145596A (en) * | 1999-03-16 | 2000-11-14 | Dallas; L. Murray | Method and apparatus for dual string well tree isolation |
US6637514B1 (en) * | 1999-05-14 | 2003-10-28 | Des Enhanced Recovery Limited | Recovery of production fluids from an oil or gas well |
US6481504B1 (en) * | 1999-06-29 | 2002-11-19 | Fmc Corporation | Flowline connector with subsea equipment package |
US6648072B1 (en) * | 1999-07-20 | 2003-11-18 | Smith International, Inc. | Method and apparatus for delivery of treatment chemicals to subterranean wells |
US6460621B2 (en) * | 1999-12-10 | 2002-10-08 | Abb Vetco Gray Inc. | Light-intervention subsea tree system |
US6675900B2 (en) * | 2000-01-27 | 2004-01-13 | David C. Baskett | Crossover tree system |
US6612368B2 (en) * | 2000-03-24 | 2003-09-02 | Fmc Technologies, Inc. | Flow completion apparatus |
US6557629B2 (en) * | 2000-09-29 | 2003-05-06 | Fmc Technologies, Inc. | Wellhead isolation tool |
US20040026084A1 (en) * | 2000-11-08 | 2004-02-12 | Ian Donald | Recovery of production fluids from an oil or gas well |
US6554075B2 (en) * | 2000-12-15 | 2003-04-29 | Halliburton Energy Services, Inc. | CT drilling rig |
US6612369B1 (en) * | 2001-06-29 | 2003-09-02 | Kvaerner Oilfield Products | Umbilical termination assembly and launching system |
US6902005B2 (en) * | 2002-02-15 | 2005-06-07 | Vetco Gray Inc. | Tubing annulus communication for vertical flow subsea well |
US6763890B2 (en) * | 2002-06-04 | 2004-07-20 | Schlumberger Technology Corporation | Modular coiled tubing system for drilling and production platforms |
US7073592B2 (en) * | 2002-06-04 | 2006-07-11 | Schlumberger Technology Corporation | Jacking frame for coiled tubing operations |
US6966383B2 (en) * | 2002-12-12 | 2005-11-22 | Dril-Quip, Inc. | Horizontal spool tree with improved porting |
US6907932B2 (en) * | 2003-01-27 | 2005-06-21 | Drill-Quip, Inc. | Control pod latchdown mechanism |
US7201229B2 (en) * | 2003-10-22 | 2007-04-10 | Vetco Gray Inc. | Tree mounted well flow interface device |
US20090025936A1 (en) * | 2004-02-26 | 2009-01-29 | Des Enhanced Recovery Limited | Connection system for subsea flow interface equipment |
US7243729B2 (en) * | 2004-10-19 | 2007-07-17 | Oceaneering International, Inc. | Subsea junction plate assembly running tool and method of installation |
US20100300700A1 (en) * | 2006-08-18 | 2010-12-02 | Cameron International Corporation | Wellhead Assembly |
US20080047714A1 (en) * | 2006-08-28 | 2008-02-28 | Mcmiles Barry James | High pressure large bore utility line connector assembly |
Cited By (30)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US8167049B2 (en) | 2002-07-16 | 2012-05-01 | Cameron Systems (Ireland) Limited | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US10107069B2 (en) | 2002-07-16 | 2018-10-23 | Onesubsea Ip Uk Limited | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US9556710B2 (en) | 2002-07-16 | 2017-01-31 | Onesubsea Ip Uk Limited | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US8746332B2 (en) | 2002-07-16 | 2014-06-10 | Cameron Systems (Ireland) Limited | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US8733436B2 (en) | 2002-07-16 | 2014-05-27 | Cameron Systems (Ireland) Limited | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US8469086B2 (en) | 2002-07-16 | 2013-06-25 | Cameron Systems (Ireland) Limited | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US8281864B2 (en) | 2003-05-31 | 2012-10-09 | Cameron Systems (Ireland) Limited | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US7992633B2 (en) | 2003-05-31 | 2011-08-09 | Cameron Systems (Ireland) Limited | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US8091630B2 (en) | 2003-05-31 | 2012-01-10 | Cameron Systems (Ireland) Limited | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US20100206546A1 (en) * | 2003-05-31 | 2010-08-19 | Cameron International Corporation | Apparatus and Method for Recovering Fluids From a Well and/or Injecting Fluids Into a Well |
US20100206547A1 (en) * | 2003-05-31 | 2010-08-19 | Cameron International Corporation | Apparatus and Method for Recovering Fluids From a Well and/or Injecting Fluids Into a Well |
US8122948B2 (en) | 2003-05-31 | 2012-02-28 | Cameron Systems (Ireland) Limited | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US8066067B2 (en) | 2003-05-31 | 2011-11-29 | Cameron International Corporation | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US8220535B2 (en) | 2003-05-31 | 2012-07-17 | Cameron Systems (Ireland) Limited | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US7992643B2 (en) | 2003-05-31 | 2011-08-09 | Cameron Systems (Ireland) Limited | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US8622138B2 (en) | 2003-05-31 | 2014-01-07 | Cameron Systems (Ireland) Limited | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US8573306B2 (en) | 2003-05-31 | 2013-11-05 | Cameron Systems (Ireland) Limited | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US8540018B2 (en) | 2003-05-31 | 2013-09-24 | Cameron Systems (Ireland) Limited | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
US8066076B2 (en) | 2004-02-26 | 2011-11-29 | Cameron Systems (Ireland) Limited | Connection system for subsea flow interface equipment |
US8776891B2 (en) | 2004-02-26 | 2014-07-15 | Cameron Systems (Ireland) Limited | Connection system for subsea flow interface equipment |
US9260944B2 (en) | 2004-02-26 | 2016-02-16 | Onesubsea Ip Uk Limited | Connection system for subsea flow interface equipment |
US8066063B2 (en) | 2006-09-13 | 2011-11-29 | Cameron International Corporation | Capillary injector |
US8297360B2 (en) | 2006-12-18 | 2012-10-30 | Cameron International Corporation | Apparatus and method for processing fluids from a well |
US8776893B2 (en) | 2006-12-18 | 2014-07-15 | Cameron International Corporation | Apparatus and method for processing fluids from a well |
US9291021B2 (en) | 2006-12-18 | 2016-03-22 | Onesubsea Ip Uk Limited | Apparatus and method for processing fluids from a well |
US8104541B2 (en) | 2006-12-18 | 2012-01-31 | Cameron International Corporation | Apparatus and method for processing fluids from a well |
US8479571B2 (en) | 2007-04-19 | 2013-07-09 | Fmc Technologies, Inc. | Christmas tree with internally positioned flowmeter |
US20090308152A1 (en) * | 2007-04-19 | 2009-12-17 | Fmc Technologies, Inc. | Christmas tree with internally positioned flowmeter |
US8104337B2 (en) * | 2007-04-19 | 2012-01-31 | Fmc Technologies, Inc. | Christmas tree with internally positioned flowmeter |
US10989008B2 (en) | 2016-11-24 | 2021-04-27 | Total E&P Danmark A/S | Cap for a hydrocarbon production well and method of use |
Also Published As
Similar Documents
Publication | Publication Date | Title |
---|---|---|
US10415346B2 (en) | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well | |
AU2012238329A1 (en) | Apparatus and Method for Recovering Fluids From a Well and/or Injecting Fluids into a Well | |
CA2826503C (en) | Apparatus and method for recovering fluids from a well and/or injecting fluids into a well |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
AS | Assignment |
Owner name: CAMERON SYSTEMS (IRELAND) LIMITED, IRELAND Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:DES ENHANCED RECOVERY LIMITED;REEL/FRAME:024644/0314 Effective date: 20070620 |
|
FEPP | Fee payment procedure |
Free format text: PAYOR NUMBER ASSIGNED (ORIGINAL EVENT CODE: ASPN); ENTITY STATUS OF PATENT OWNER: LARGE ENTITY |
|
STCF | Information on status: patent grant |
Free format text: PATENTED CASE |
|
IPR | Aia trial proceeding filed before the patent and appeal board: inter partes review |
Free format text: TRIAL NO: IPR2016-00378 Opponent name: FMC TECHNOLOGIES, INC. Effective date: 20151228 |
|
FPAY | Fee payment |
Year of fee payment: 4 |
|
AS | Assignment |
Owner name: CAMERON SUBSEA IP LIMITED, IRELAND Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:CAMERON SYSTEMS (IRELAND) LIMITED;REEL/FRAME:037960/0152 Effective date: 20130610 Owner name: ONESUBSEA IP UK LIMITED, UNITED KINGDOM Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:CAMERON SUBSEA IP LIMITED;REEL/FRAME:037960/0278 Effective date: 20130624 Owner name: CAMERON SYSTEMS (IRELAND) LIMITED, IRELAND Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:DES OPERATIONS LIMITED;REEL/FRAME:038071/0028 Effective date: 20130604 |
|
STCV | Information on status: appeal procedure |
Free format text: APPLICATION INVOLVED IN COURT PROCEEDINGS |
|
MAFP | Maintenance fee payment |
Free format text: PAYMENT OF MAINTENANCE FEE, 8TH YEAR, LARGE ENTITY (ORIGINAL EVENT CODE: M1552); ENTITY STATUS OF PATENT OWNER: LARGE ENTITY Year of fee payment: 8 |
|
FEPP | Fee payment procedure |
Free format text: MAINTENANCE FEE REMINDER MAILED (ORIGINAL EVENT CODE: REM.); ENTITY STATUS OF PATENT OWNER: LARGE ENTITY |
|
FEPP | Fee payment procedure |
Free format text: 11.5 YR SURCHARGE- LATE PMT W/IN 6 MO, LARGE ENTITY (ORIGINAL EVENT CODE: M1556); ENTITY STATUS OF PATENT OWNER: LARGE ENTITY |
|
MAFP | Maintenance fee payment |
Free format text: PAYMENT OF MAINTENANCE FEE, 12TH YEAR, LARGE ENTITY (ORIGINAL EVENT CODE: M1553); ENTITY STATUS OF PATENT OWNER: LARGE ENTITY Year of fee payment: 12 |